bluuebunny/crossref_metadata_2025_split huggingface dataset:
Enterprise Risk Management in the Petroleum Industry Through Information Validation
Authors: Randall Scott W. , Griffin Don P. , Harrell D. Ronald 
Published: December 2007

Abstract
Shareholders, board members, regulators and the general public are demanding reasonable assurance of value growth, governance and compliance through corporate level risk management at petroleum exploration and production companies. However, at the heart of this assurance is the reliability of information. Petroleum reserves estimating and reservoir engineering techniques provide assurance around the reliability of estimated hydrocarbon quantities. These same techniques can be combined with tools from the fields of operational risk management and strategic planning to support the emerging practice of Enterprise Risks Management (ERM) at oil and gas companies. This paper presents a framework for achieving reasonable assurance of the reliability of information to support ERM at oil and gas companies through use of a various tools and techniques.
Using examples from integrated multinational upstream companies, it is shown how qualitative and quantitative tools could be tied together into a systematic ERM process that complies with minimum standards for information integrity. Reference is made to the Resource Management System approved in 2007 by the SPE Board and its industry partners AAPG, WPC and SPEE and its guidance on principles of reserves estimating as an example of best practice in validating information. Sample data from the field of reserves estimating and resource estimation is presented to illustrate information validation approaches.
The value of reliable information to support enterprise risk management is demonstrated by showing how various stakeholder groups are satisfied through reasonable assurance. In turn, this assurance leads to competitive advantage for oil and gas companies in terms of cost of capital, reduced regulatory scrutiny, and improved strategic focus.
Operational risk management tools and techniques have been used for many years in functional areas ranging from petroleum geology to major project and commodity price risk management. However, techniques from the broader fields of strategic planning, market research and quality management have not been integrated with methods from petroleum reserves and resource classification to manage enterprise level risks. This paper suggests that an information validation framework supported by tools and techniques from beyond the field of operational risk management can provide petroleum companies with sustained competitive advantage.
Achieving Superior Application Engineering: Proven Holistic Approach Disseminated to a Wider Community Key to Success
Authors: Redshaw J. P. , Scotchman A. D. , Laing R. , Dwyer J. P. , Trichel D. K. 
Published: December 2007

Abstract
Delivery of performance through reduced well time while maintaining optimum wellbore quality requires a thorough understanding of the drilling environment, recognizing geological and drilling process hazards. Studying each component of the drilling system and environment in isolation prevents identifying the root cause of or fully understanding the problem, leading to less than optimal solutions and failure to deliver performance. To overcome performance barriers, we must first have an in-depth understanding of the root cause by taking a holistic approach to the analysis of the drilling environment.
This organization developed a successful process within a dedicated drilling optimization group that enabled a structured approach to understanding the complete drilling environment. This successful process, founded on the continuous improvement cycle—plan, execute, analyze, and capture— delivered practices and technology recommendations to realize performance gains and significant well-time reduction. Taking lessons learned from one well and implementing these on subsequent wells delivered further performance improvements.
The original drilling optimization group comprised a small team of highly disciplined engineers focused on detailed application analysis to minimize barriers to drilling performance improvement. This group's work was the foundation of drilling knowledge tools within the organization; this work led to the development of industryleading methodologies for data analysis and best drilling practices.
The performance advantages realized by the team using this process lead the organization to recognize that its wider drilling community would benefit from the use of this process to deliver consistent performance gains.
The authors will describe the process and how it has been applied to the wider drilling community to meet the needs of individual engineering disciplines and groups.
The challenge to distribute the holistic approach and continuous improvement philosophy from a core group to the wider organization involved raising competency standards and the provision of dedicated knowledge transfer tools, creating an enabling environment to allow proactive performance management of specific applications. Finally, the authors will present several case studies that document success with the process.
Estimation of Formation Stresses Using Radial Variation of Three Shear Moduli—A Case Study From a High-Pressure and High-Temperature Reservoir in a Norwegian Continental Shelf
Authors: Sinha Bikash K. , Vissapragada Badarinadh , Wendt Anke S. , Kongslien Marit , Eser Hakan , Skomedal Eiliv , Renlie Lasse , Pedersen Erik Sandtorv 
Published: December 2007

AbstractFormation stresses and rock strength together with wellbore and pore pressures are important inputs to failure models whose predictions help in well planning, wellbore stability and production. A complete characterization of formation stresses requires estimation of the overburden, maximum and minimum horizontal stresses together with pore pressure as a function of depth. The overburden stress is reliably estimated by integrating with depth the formation bulk density, and pore pressure is directly measured in a permeable reservoir interval. The maximum and minimum horizontal stresses can be estimated from borehole sonic data in the presence of crossing dipole dispersions. A new stress magnitude estimation algorithm inverts radial variation of the three shear moduli together with the overburden stress and pore pressure at a given depth for the maximum and minimum horizontal stress magnitudes and formation nonlinear constants referred to a local reference state. The algorithm uses equations relating differences in the dipole shear moduli at two radial positions and corresponding differences in the principal stresses obtained from near-wellbore stress concentrations using the Kirsch's equations. Radial positions in the plastically yielded region close to the borehole surface are excluded from the inversion algorithm.Processing of sonic data yields crossing dipole dispersions in three sand intervals in a development well drilled in a high pressure (770 bars) gas condensate field operated by Statoil in the Norwegian continental shelf. Results for both the maximum and minimum horizontal stress magnitudes are consistent in the three sand intervals in the Bent reservoir of the Kvitebjorn field. Estimated minimum horizontal stress magnitude is in good agreement with the mini-frac test conducted at a nearby depth. The maximum horizontal stress direction coincides with the fast-shear azimuth obtained from the Alford rotation of cross-dipole waveforms. Horizontal stress magnitude results have helped in refining the mechanical earth model and in subsequent drilling of development wells in this field.
Grid Modeling and Numerical Simulation of Multiphase Flow in Heterogeneous Reservoirs Using Orthogonal Collocation Schemes
Authors: Abhulimen Kingsley E. , Anubi Moses O. 
Published: December 2007

Abstract
Complex features such as geological features (e.g. faults, pinch outs, inclined beddings); well related (multilateral wells of general orientation) can have significant impact on reservoir performance as well as reservoir fluid flow. These features are difficult to model using traditional finite difference methods, hence sophisticated gridding and discretization techniques are required if their effects are to be captured accurately in numerical reservoir flow simulators. Our model for reservoir stimulation uses advanced orthogonal collocation numerical simulators as well as grid transformation of the Cartesian coordinates (x, y, z) into curvilinear coordinates (ξ(r), ξ(θ), ξ(z)) to accommodate general three dimensional deviated wells and complex reservoir geometry for both structured and unstructured geology for multiphase flow of hydrocarbon in complex reservoir formations. Our model was applied to simulate multiphase flow in complex reservoir formations in Nigeria using a sophisticated computer numerical program developed in mathlab to model for pinch outs, well deviated formations using different mix of injectors-producers schemes. Data was sourced from an operating oil company typifying some complex reservoir formations. It is now possible to determine non-conventionality of a reservoir and actually determine where and when it sets in by studying both the pressure and flow performance plots. It is clear that non-conventionality of reservoir is more important at the center of the reservoir payzone coordinates. Using our transformed coordinates, we located non-conventionality of the reservoir system at ξ (r ) = 0.42566 Non-conventionality in the studied reservoir is determined from increase activity in flow and pressure deviation charteristics as observed around the coordinates ξ(r) = 0.42566 using inference of the flow and pressure performance plots.
Enabling Automated Workflows for Production
Authors: Szatny Michael 
Published: December 2007

Abstract
The Oil & Gas industry faces manpower, equipment, and service shortages as it tries to cope with a world energy demand that is projected to grow from 230 million barrel of oil equivalents per day (boe/d) today to 335 million boe/d in 2030. As such, it will rely heavily on technological advances to meet future energy demands. Additionally, the most experienced engineering staff will retire in the next 5-10 years. Therefore, significant workforce productivity gains will have to be realized through digital oilfield automation initiatives to manage future levels of E&P activity.
Many production workflows require engineers to coordinate data flows between disparate numbers of applications. Studies have shown that about 70% of an engineers time is spend gathering, formatting, and translating data for use in these different applications. For standard production activities, ie. workflows, this time can be drastically reduced by creating an automated system to execute the prescribed workflow. The automated workflow not only reduces the engineers valuable time doing these repetitive tasks, but also ensures consistency in methods, reduces the likelihood of input errors, and creates a repository for "best practices" that can be maintained long term as personnel (and their knowledge) is moved into and out of the production asset.
For many years automated workflows have been a part of the design and production cycles in other industries like Aerospace, Automotive, and Industrial Manufacturing. These industries have been tying together applications and data sources along with using stochastic analysis methods and optimization to improve their overall productivity.
This is exactly what the Oil & Gas industry needs today. The tools used to orchestrate these workflows across a wide variety of applications, requirements and IT systems have matured to a state that the creation of new automated workflows is virtually "plug & play".
A Basic Approach to Wellbore Two-Phase Flow Modeling
Authors: Hasan A. R. , Kabir C. S. , Sayarpour M. 
Published: December 2007

Abstract
This study presents a simplified two-phase flow model using the drift-flux approach to well orientation, geometry, and fluids. For estimating the static head, the model uses a single expression for liquid holdup, with flow-pattern-dependent values for flow parameter and rise velocity. The gradual change in the parameter values near transition boundaries avoids discontinuity in the estimated gradients, unlike most available methods. Frictional and kinetic heads are estimated using the simple homogeneous modeling approach.
We present a comparative study involving the new model as well as those that are based on physical principles, also known as semimechanistic models. These models include those of Ansari et al, Gomez et al., and OLGA. Two other widely used empirical models, Hagedorn and Brown and PE-2, are also included. The main ingredient of this study entails the use of a small but reliable dataset, wherein calibrated PVT properties minimizes uncertainty from this important source.
Statistical analyses suggest that all the models behave in a similar fashion and that the models based on physical principles appear to offer no advantage over the empirical models. Uncertainty of performance appears to depend upon the quality of data input, rather than the model characteristics.
Effects of Reservoir Heterogeneities on the Steam-Assisted Gravity Drainage Process
Authors: Chen Q. , Gerritsen M. G. , Kovscek A. R. 
Published: December 2007

Abstract
The success of steam-assisted gravity drainage (SAGD) has been demonstrated by both field and laboratory studies mostly based on homogeneous reservoirs and reservoir models. A comprehensive understanding of the effects of reservoir heterogeneities on SAGD performance is required, however, for wider and more successful implementation. This work presents a numerical investigation of the effects of reservoir heterogeneities on SAGD using a stochastic model of shale distribution. Two flow regions, the near well region (NWR) and the above well region (AWR), are identified to decouple the complex effects of reservoir heterogeneities on the SAGD process. Numerical simulations are conducted with various realizations of shale distribution to compare SAGD performance in terms of the effects of NWR and AWR. Hydraulic fracturing is proposed to enhance steam chamber development for reservoirs with poor vertical communication and the feasibility of hydraulic fracturing is discussed in terms of in-situ stresses and well orientations. Fracturing the formation around both the injection and production wells is found to improve steam distribution, oil production rate, and the oil-steam ratio.
Real-Time Performance Analysis of Water-Injection Wells
Authors: Izgec B. , Kabir C. S. 
Published: December 2007

Abstract
This work presents a complete reformulation of the Hall method involving both pre- and post-breakthrough situations. Two approaches involving both transient and material-balance methods produced very similar solutions, which were verified with the results of coupled geomechanical/fluid-flow simulations. The new formulations allow tracking the expanding water-bank radius from inception to breakthrough. Pressure of this bank at the water/oil interface is evaluated at every timestep, thereby allowing continuous update of the ‘external pressure’ in Hall's formulation. We show that Hall's formulation is a particular case of the proposed approach. Several simulated and field examples demonstrate the value of reformulated Hall analysis.
Because Hall formulation involves an integral, the resultant signature, by nature, is insensitive in revealing clues about subtle changes that may occur during formation fracturing or plugging. We observed that the derivative of modified-Hall integral, obtained analytically, provides definitive signatures about fracturing or plugging.
The new interpretation approach is particularly suitable for projects at the inception of flooding. Mature projects can benefit equally from the new tool. Perhaps the biggest appeal of the proposed tool lies in the green fields, where real-time data are readily available.
Use of Artificial Intelligence Techniques for Predicting Irreducible Water Saturation - Australian Hydrocarbon Basins
Authors: Goda H. M. , Maier H. R. , Behrenbruch P. 
Published: December 2007

Abstract
Determination of original hydrocarbon in place, OHIP, is a vital task in petroleum development. The estimation of appropriate rock and fluid properties is a requirement, with irreducible water saturation, Swir, being one of the key parameters. A representative Swir is also required when conducting multi-phase experiments, for example relative permeability determination. Furthermore, Swir has an influence on residual oil saturation during tertiary recovery.
Conducting primary drainage capillary pressure experiments to measure Swir is the industry-established practise. Such experiments tend to require considerable resources and long time periods to complete. As a consequence, a limited number of representative core plugs are typically considered, often leading to data gaps for some facies within a reservoir. In such situations, an empirical model may be useful in predicting Swir.
In a recent study, artificial neural networks have been applied successfully to the estimation of irreducible water saturation (Swir) for Australian formations. The model demonstrates a superior performance when compared with other, conventional models. This paper features the translation of the artificial neural network model into a simple mathematical equation that is suitable for quick hand calculation. Moreover, a new semi-empirical model to predict Swir is presented, containing five adjustable constants. The optimal values for these constants were obtained by minimizing the calculated error utilizing a genetic algorithm. Both neural network and semi-empirical models were developed, calibrated and validated by using an extensive data set gathered for Australian hydrocarbon basins.
LBC Viscosity Modeling of Gas Condensate to Heavy Oil
Authors: Yang Tao , Fevang Øivind , Christoffersen Kjell , Ivarrud Endre 
Published: December 2007

Abstract
Due to simplicity, consistency and flexibility, the Lohrenz-Bray-Clark (LBC) correlation is the most widely used viscosity model in reservoir engineering. Unfortunately the LBC viscosity model does not accurately predict liquid viscosity. Consequently it is necessary to tune the calculated viscosities. Tuning of the LBC viscosity model is normally performed by modifying the critical volumes of the C7+ components and/or the LBC coefficients. The tuning procedure is not straight forward. Special attention is required for three challenging fluid systems: viscosity of the condensed oil from gas condensates, viscosity changes in connection with gas injection and viscosity of heavy oils.
This paper describes guidelines for proper tuning and consistency checking of the LBC viscosity model. Instead of using various correlation-estimated critical volumes for the C7+ components as in most PVT software, the initial critical volumes of the C7+ components are calculated based on component viscosities estimated from a dead-oil empirical correlation. Global regression to the measured viscosity data is then made with modifiers to the initial critical volumes. This procedure guarantees monotonically increasing component viscosities for the C7+ components. In the case of any regression on LBC coefficients, it is very important to maintain a monotonic relation of viscosity vs. reduced density.
Viscosity data from three Norwegian offshore reservoirs, from gas condensate to heavy oil, are used as examples. The guidelines for tuning the LBC viscosity model presented in this paper provide practical insight and understanding of how to apply the LBC viscosity model to various fluid systems.
Managing Total Circulation Losses with Crossflow While Drilling: Case History of Practical Solutions
Authors: Suyan K. M. , Dasgupta D. , Sanyal D. , Sharma Vinod , Jain V. K. 
Published: December 2007

Abstract
Lost circulation during drilling increases the drilling costs and also enhances possibility of stuck pipe. Generally, viscous mud pills with lost circulation materials and gels or cement plugs are placed to allow plugging of loss circulation zone. But in case of total circulation loss in conjunction with cross flow condition, even repeated LCM-mud plugs followed with cement plugs do not guarantee the durable sealing of lost zone. This paper discusses the properties, mechanism and placement technique for successful plugging off lost zone in such cases where very few lost circulation remedies were effective and more than several hundred cubic meter of drilling fluid and cement were already lost.
Details development of a novel sealant system consisting of an elastomer combined with cross-linking polymers, activator and bridging agents which provided quick, reliable control of loss has been deliberated in this paper. Initial low viscosity of this sealant allow easy placement against the lost zones and then gel activated near wellbore to set and form a stiff, rubbery gel stick with formation sediments to eliminate further losses. This development offers a proven means of controlling severe circulation losses resulting from large fractures or vugular spaces. The composition can be engineered to produce durable cross-linked polymeric rigid gel across a vide range of densities 8.6-14 ppg and temperature 45120 deg C. Addition of accelerators or retarders during mixing controls setting time and eliminates risk of premature setting inside the string while pumping.
Laboratory tests revealed effectiveness of this polymeric based sealant treatment and can improve stress around wellbore by forming a deformable, viscous and cohesive sealant inside a lost circulation fracture. Field application shows the restoration of well bore integrity in total loss with cross flow condition by the innovative approach of using this cross linked polymeric stiff rubbery gel in combination with high volume cement plug.
This paper deals with aspect of important lessons learnt from the field application of the developed cross linked polymeric stiff rubbery gel to control total circulation losses in conjunction with cross-water flow.
Design of Carbon Dioxide Storage in a North Sea Aquifer Using Streamline-Based Simulation
Authors: Qi Ran , Beraldo Valcir , LaForce Tara , Blunt Martin J. 
Published: December 2007

Abstract
We propose a carbon storage strategy where CO2 and brine are injected into an aquifer together followed by brine injection alone. This renders 80-95% of the CO2 immobile in pore-scale (10s μm) droplets in the porous rock; over thousands to billions of years the CO2 may dissolve or precipitate as carbonate, but it will not migrate upwards and so is effectively sequestered. The CO2 is trapped during the decades-long lifetime of the injection phase, reducing the need for extensive monitoring for centuries. The method does not rely on impermeable cap rock to contain the CO2; this is only a secondary containment for the small amount of remaining mobile gas. Furthermore, the favorable mobility ratio between injected and displaced fluids leads to a more uniform sweep of the aquifer leading to a higher storage efficiency than injecting CO2 alone.
This design is demonstrated through the incorporation of a recent model of trapping and relative permeability hysteresis based on pore-scale modeling into a field-scale streamline-based simulator. One-dimensional results are verified through comparison with analytical solutions. Results are then shown for storage in a North Sea aquifer. We design injection to give optimal storage efficiency and to minimize the amount of water injected; for the case we study injecting CO2 with a fractional flow between 85 and 100% followed by a short period of chase brine injection gives the best performance.