bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Scalable Massively Parallel Dual-Porosity Dual-Permeability Simulator for Fractured Reservoirs with Super-K Permeability
Authors: Al-Shaalan Tareq M. , Fung Larry S.K. , Dogru Ali H. 
Published: December 2007

Abstract
Modeling Middle East giant carbonate reservoirs with fractures and super-k conductivity present unique challenges to conventional simulation approaches. Fractures in these giant oil fields can exist as fracture swamp neighboring fault zones. These regional/local fractures can interact with Super-K layers (high permeability stratiform) which form extremely high conductivity to fluid flow. Typically, meaningful simulation for such an oil field requires the use of millions of grid cells involving thousands of wells. These reservoirs are not the classical dual porosity where matrix permeability is poor and does not form a part of the global flow path. Dual porosity dual permeability (DPDP) formulation allowing a flexible regional representation of both single porosity and dual porosity behavior on a cell by cell basis is more suitable.
A parallel dual porosity dual permeability simulator has been developed to efficiently solve multi-million grid cell fractured reservoirs problems with super-k fracture permeability. To be effective, the simulator has to engage tens to hundreds of processors in a highly scalable manner. This paper discusses the formulation, the data design and solution procedures involved in this development.
The parallelization paradigm is the mixed approach with MPI (Message Passing Interface) and OpenMP (Open Message Passing). These parallelization approaches are open standards supported by most major hardware vendors. This allows for easy portability among various hardware architectures. However, the data design and solution methods discussed herein are amenable to MPI only or other parallelization approaches as well. The mixed paradigm approach is flexible and allows various combination and permutation of MPI processes and OpenMP threads to be used to solve a problem.
Results are presented for a multi-million cell fractured reservoir simulation with super-k involving thousands of wells and over 60 years of history match. We present simulation results, computational efficiency and parallel scalability on the IBM Nighthawk II, as well as on the PC Xeon Linux cluster hardware.
Modeling of Performance Behavior in Gas Condensate Reservoirs Using a Variable Mobility Concept
Authors: Wilson B. W. , Archer R. A. , Blasingame T. A. 
Published: December 2007

Abstract
This work provides a concept for modelling well performance behavior in a gas condensate reservoir using an empirical model for the gas mobility function. This model is given by: k=kmin+(kmax−kmin)[1−exp[−1αr2t]]
This concept model represents the minimum gas permeability (or mobility) near the wellbore and the maximum (or original) gas permeability (or mobility) in the "dry gas" portion of the reservoir, as well as the transition regime. This model was constructed based on observations derived from numerical simulation results where the saturation, effective permeability, and gas mobility are presented as functions of distance in the reservoir.
The utility of this concept is that it can be used to develop a pressure solution for the behavior of the gas phase produced from a gas condensate reservoir. This new solution is validated against numerical simulation and has been presented graphically for use in well test analysis (in the form of "type curves"). The advantage of this solution over the conventional radial composite reservoir solutions is that the evolution of the condensate zone can be represented and evaluated as it occurs in time. The obvious limitation is the simplified form of the kg profile as a function of radius and time, as well as the dependence/appropriateness of the "α" coefficient.
Application of this new pressure solution to well test analysis is proposed — and comparisons to the radial composite (and other reservoir models) are also presented. Our goal is to demonstrate that the proposed solution has potential utility in the analysis and interpretation of reservoir performance data (most likely, pressure drawdown and pressure buildup test data).
We recognize that the simplicity of this approach may have practical limitations — for example, we consider a radially-varying
mobility profile, but we also assume a constant diffusivity — this is a potential shortcoming that should be considered in future work.
A Quantitative Study to Assess the Value of Pressure Data Acquired with In-Situ Permanent Sensors in Complex 3D Reservoir Models Subject to Two-Phase Fluid Flow
Authors: Wu Z. , Alpak F. O. , Torres-Verdín C. 
Published: December 2007

AbstractRecent advances in smart well completion technologies have enabled the dynamic acquisition of in-situ pressure measurements with sensors in direct hydraulic contact with rock formations. In addition to the immediate impact of in-situ sensors as tools for real-time, reactive reservoir management and control, usage of in-situ pressure sensors has long-term benefits. Devising an optimal macro-management strategy for hydrocarbon reservoirs requires more than a tool for instantaneous monitoring and control. Precise knowledge of the spatial distribution of petrophysical properties is essential for accurate reservoir delineation, management, and production forecasting. From the formation evaluation viewpoint, large volumes of flow-related data constitute an attractive prospect for robust and accurate characterization of reservoirs. In addition to static information in the form of geostatistical, seismic, and geologic data, usage of dynamic measurements remains imperative to construct accurate reservoir models amenable to production forecast.In this paper, we address the quantitative estimation of three-dimensional (3D) spatial distributions of permeability and porosity from pressure measurements acquired with in-situ permanent sensors. A pilot waterflood operation conducted with a conventional five-spot pattern is chosen as example for our numerical experiments. We assume in-situ permanent pressure sensors to be an integral part of the production-well completion and to remain completely isolated from the hydraulics of the wellbore. Therefore, these sensors perform uncorrupted measurements of in-situ formation fluid pressures. Quantitative estimation of spatial distributions of permeability and porosity is approached with a novel subspace approach and a modified Gauss-Newton inversion algorithm. This inversion strategy incorporates an adjoint formulation for the efficient computation of model sensitivities. In our inversions, the physics of two-phase fluid-flow in the 3D spatial domain is rigorously incorporated into the assessment of distributions of petrophysical properties from in-situ permanent-sensor pressure data. Comparisons are shown of the enhancement in spatial resolution and reduction of uncertainty when using in-situ permanent sensors with respect to estimations performed via standard history matching techniques.
Dynamic Neural Network Calibration of Quartz Transducers
Authors: Schultz R. L. , Chen D. 
Published: December 2007

Abstract
Quartz pressure transducers are plagued by degraded performance when subjected to thermal transients. In this paper, two new methods of calibrating quartz transducers in which a neural network is used to accomplish a dynamic calibration of a transducer pair for a range of temperatures and pressures will be described.
When a quartz pressure transducer is exposed to an environmental temperature change, thermal stress is induced in the sensing element. This thermal stress causes erroneous pressure readings until thermal equilibrium is achieved within the transducer. In order to compensate for the undesirable transient thermal effects on the pressure transducer performance, multiple past and future temperature- and pressure-sensor outputs are used as inputs to a calibrating neural network. These new methods allow the time-dependent qualities of the quartz-oscillator transducer to be included in the calibration scheme. Generally, these methods can be applied to other types of transducers subject to transient environmental effects and are not limited to quartz-oscillator transducers. A theoretical discussion of this technology is presented, followed by experimental results obtained by applying both methods to quartz pressure-transducer calibration.
Fracture Characterization for Integrated Studies: A New Approach and its Applications
Authors: Ozgen Cetin , Firincioglu Tuba , Albertoni Alejandro 
Published: December 2007

AbstractThis paper describes a new approach for fracture characterization by integrating all of the available data, geology, petrophysics, core analysis and production data. Our approach in fracture characterization produces normalized distributions for fracture presence and anisotropic connectivity. The normalized information is directly imported into the 3D flow simulator, where it can be scaled during sensitivity analyses. This fast approach enables the testing of the effect of the fracture indicators and their influence on the limits of fracture presence.In this paper, the successful applications of this fracture characterization technology to a complex fractured volatile oil reservoir with an aquifer (Sen Field, Mexico) and a fractured helium gas storage field (Bush Dome Reservoir, Texas) are presented. The results of these integrated studies are provided as proof of concept. Successful history match results obtained in a short period of time for these fields show the efficiency of the integrated fracture characterization technique.
Coalbed Methane Parametric Study: What's Really Important to Production and When?
Authors: Roadifer R. D. , Moore T. R. , Raterman K. T. , Farnan R. A. , Crabtree B. J. 
Published: December 2007

Abstract
Coalbed methane (CBM) reservoir performance is controlled by a complex set of reservoir, geologic, completion and operation parameters and the inter-relationships between those parameters. In order to identify, analyze and mitigate risks associated with any CBM prospect, one must first understand the relative importance of each of these parameters, how their relative importance changes under different constraints, and how they interactively affect CBM production. To date, no comprehensive parametric study on coalbed methane is known to have been conducted within the industry. The parametric studies that do exist in the literature have only considered a limited set of parameters and a limited range for those parameters while holding all the other parameters fixed, thus potentially skewing their results.
This comprehensive parametric study has been conducted to enhance our understanding of CBM reservoir performance. In essence, it is an analysis of an extensive Monte Carlo simulation of more than 100,000 reservoir simulations in which the reservoir, geologic, completion and operational variables that impact the production performance of CBM reservoirs were varied. While it is stated that this was a coalbed methane parametric study, coalbed methane reservoirs typically occur in conjunction with sandstones of varying quality. For that reason, one-half of the reservoir simulations modeled the production from coalbed methane reservoirs in conjunction with sandstones of varying quality and degrees of wetness (fully water charged to various degrees of gas-charge).
The study's goal was to establish the relative importance of the identified parameters and their inter-relationships, developing rank correlations between these parameters against several production end states (e.g., peak gas rates, dewatering times, cumulative gas, etc.). To avoid some of the potential problems of other similar studies, this study aimed to be as comprehensive as possible in the coverage of parameters varied with the tools available. In so doing, it provides a fuller understanding of the parameters involved in coalbed methane production and enables uncertainties and risk to be more accurately assessed for project economics, and will ultimately lead to the development of more accurate and efficient CBM screening models.
Powder River Basin Ft. Union Coal Reservoir Properties and Production Decline Analysis
Authors: Mavor Matthew J. , Russell Boyd , Pratt Timothy J. 
Published: December 2007

Abstract
After a humble beginning in the 80's, coalbed methane (CBM) production from the Powder River Basin (PRB), Wyoming, Paleocene Fort Union Formation coal beds rapidly expanded in the 90's until today there are more than 8,900 wells on production. The purpose of this paper is to evaluate gas production based upon reservoir data and to review the actual production data. We begin by reviewing available reservoir property data obtained from a specific well by core, log, and well test analysis. We use this information to investigate the range in production that may result from a well with similar properties. We then present equations for decline curve analysis and show that production rates should decline exponentially for wells with similar reservoir properties. Beginning with a largescale review of total production, we narrow down to analyze the gas and water performance of early wells and more recent wells using decline curve methods. We characterize production using "type decline curves" by combining the production from groups of wells as a function of on-production time and completed coal seam.
Development of the Wyodak Coalbed Methane Resource in the Powder River Basin
Authors: Hower T. L. , Jones J. E. , Goldstein D. M. , Harbridge W. 
Published: December 2007

Abstract
Just over ten years ago, coal bed methane production from Wyoming's Powder River Basin was virtually non-existent. Today, total gas production from Powder River Basin coals is almost 1 Bcf per day from nearly 10,000 wells. This tremendous resource is unique compared to other commercial coalbed methane plays with gas content an order of magnitude lower, and reservoir permeability values several orders of magnitude higher than other producing coal bed plays.
This paper documents the results of an ongoing evaluation of the reservoir and production characteristics of the Wyodak coals located in the fairway of the Powder River Basin activity. Most of the drilling and production to date has focused on the Wyodak and equivalent coal horizons. A reservoir simulation model has been constructed covering 136 sections and including over 1300 wells. A detailed geological description and a large data base of core data and test results were used in the construction of the model. Historical gas production, water production, and reservoir pressure data were successfully matched from 1993 to the present during the calibration of the simulation model. The calibrated model was then used to evaluate optimum development strategies for this shallow, high permeability coal resource.
This paper discusses the production characteristics of the Wyodak coal, the impact of well spacing and well timing on the recovery factor, and the influence of outside factors such as recharge from the regional aquifer. Our results contradict conclusions reported in prior studies concerning the influx of water from adjacent sand horizons. In addition, the effects of multiple well interference and depletion of undrilled portions of the coal by existing wells are documented and discussed.
E&P a Dynamic Profitable Growth Business
Authors: McKay Aidan 
Published: December 2007

Abstract
This general paper addresses the conflicting and competing challenges in E&P. It provides a high level overview of the challenge ahead in meeting global energy demand and also describes the status of the E&P business today and the forces changing the industry nature. It asks where will the industry go to find the oil and gas needed to replace field decline and achieve growth, and what might it cost. Global hydrocarbon demand from wellbores is forecast to almost double to around 220 mln boe/d by 2030 in association with the energy needs of a global population of 8 billion. In addition to installing supply capacity for such growth, E&P must also replace reservoir decline at existing fields. Meeting this supply need translates to E&P being a growth business with high single digit growth of supply capacity.
The current world hydrocarbon proven reserves pool is broadly 1100 bln bbl oil, 750 mln boe of gas and 3000 bln boe of unconventional oils like bitumen and oil sands resources. There is sufficient conventional hydrocarbons for 40 years supply at current demand levels and more if unconventionals are included. The historical success of the E&P industry in ensuring demand is met in a volatile and changing world, has perhaps led society as a whole to take energy demand needs for granted. The paper suggests that the future for the E&P industry is going to be much more difficult given the scale of demand growth and the investment levels required which are almost beyond belief.
We in E&P need to educate society to the scale of R&D and investments required, the time taken to access and develop hydrocarbons and to translate them from geological deposits to vital fuels or feedstock's. For demand to be met, the E&P industry will have to be highly innovative whilst providing acceptable returns for investors. This is a significant task.
Application of Lean Six Sigma in Oilfield Operations
Authors: Buell R. S. , Turnipseed S. P. 
Published: December 2007

Abstract
This paper summarizes experience and results improving business performance using Lean Six Sigma in upstream oil and gas operations in North Ame rican and Asia. Background and history on Lean, Six Sigma, and ISO systems are provided. The role ISO quality systems can play in supporting Lean and Six Sigma is explained and demonstrated with examples. Overviews of completed Lean Six Sigma projects are provided for well testing, rod pump repair, water treatment, oil treatment, well stimulation, and production logging.
Effective Techniques for Outsourcing Engineering Projects
Authors: McGowen Harold E. 
Published: December 2007

Abstract
Outsourcing is a strategic tool for improving performance and managing cash flow in rapidly growing operating companies. Outsourcing engineering projects is a means to bring specialized expertise and new ideas into an organization, freeing internal resources to concentrate on ongoing operations and core competencies, without a long-term increase in overhead. Through the application of best practices Project Management techniques, engineering project outsourcing can be a vital management tool for initiating technical innovation, expansion into new development or exploration areas, and gaining competitive advantage through intensive analysis of a specific problem.
The upstream petroleum industry routinely achieves effective outsourcing in operations type projects1. For example, drilling managers consistently utilize a detailed project plan as well as daily cost and progress reporting to control and manage drilling operations. Ironically, the engineering design process that creates the operations procedures, such as drilling programs and completion procedures, which control the ultimate quality of the end product, is often managed using informal methods, or not managed at all.
Many operators minimize overhead by maintaining small staffs of generalists capable of managing a variety of projects. From time to time, a particularly thorny technical issue or unusually heavy work load requires some operators to contract with consulting engineering firms or independent consultants in order to accomplish project objectives. Unfortunately, the typical ad hoc methods of engineering project outsourcing often produce poor results. Consequently, many operators prefer staff augmentation to outsourcing an entire engineering project. Unfortunately, staff augmentation does not eliminate the problems inherent in attempting to manage engineering projects in a resource constrained, operations-driven environment, and the operator loses the potential benefits of effectively managed engineering outsourcing. This paper describes a proven method of outsourcing engineering projects that improves quality while bringing projects in on time and within budget.
Optimizing the Organizational Design of a Typical Upstream Exploration and Production Company
Authors: Rabbino Hal , Dunham Cleon , Ritchie-Dunham James 
Published: December 2007

Abstract
Most upstream exploration and production (E&P) companies or departments in the petroleum industry are facing significant compression in resources – both staffing and funding. These organizations are being challenged to produce more oil and gas, under more difficult conditions, at lower costs, and with smaller and less well trained staffs.
This paper presents a process for analyzing the business strategy of a typical E&P organization. It is a comprehensive process that includes all the relevant strategic elements in a rigorously testable, integrative framework that is simple to understand and focuses the strategy on the business's key purpose. This process is known as GRASP. It highlights the Goals, Resources, Actions, Structures, and People that such an organization must have (or acquire) and effectively deploy to successfully compete in the modern E&P environment.
This analysis addresses such difficult questions as:
What are the optimal:
Organizational structures for surviving and thriving in the modern E&P business Tradeoffs in satisfying financial shareholders, employees, suppliers, and external stakeholders Interfaces and interactions between the separate groups in the organization Allocations of people and financial resources to achieve optimum productivity Degrees of staff development and training for optimum performance Balances between primary and secondary recovery to optimize economic operation Approaches between manual and automated operations Planning and funding for new equipment vs. repair and maintenance of existing equipment Investing resources for safety and environmental protection.
This analysis is based on a sophisticated causal (cause and effect) evaluation of the organization, with several technological enhancements that clarify areas where leverage is needed and can be applied to make significant improvements. We present one case study where this analysis has been applied and several insights that have been gained from applications of this technology.
Obtain an Optimum Artificial Neural Network Model for Reservoir Studies
Authors: Du Yuqi , Weiss W. W. , Jianyun Xu , Balch R. S. , Dacun Li 
Published: December 2007

Abstract
Artificial Neural Networks (ANNs) excel in dealing with uncertainty, fuzziness, incompleteness, and poorly defined nonlinear systems. These factors widely exist in reservoir studies. Training neural networks is a notoriously difficult problem. In training neural networks, one of the major pitfalls is overtraining, analogous to curve fitting for rule-based systems. Emperical evidence suggests that the number of records must exceed the number of neural network weights by a factor of two to minimize overtraining problems.
Undertraining is another problem in which the ANNs with a simpler architecture cannot master the basic rules of input patterns. The aftermath of overtraining is much worse than that of undertraining. Based on the trial and error method, this paper first explores the overtraining problem using various defined functions and then applies the results to an oil well in the Nash Draw field in New Mexico. An optimum architecture was found for the field problem. Solutions to minimize neural network overtraining problems are presented.