bluuebunny/crossref_metadata_2025 huggingface dataset:
Compositional and Non-Isothermal Simulation of CO2 Sequestration in Naturally Fractured Reservoirs/Coalbeds: Development and Verification of the Model
Authors: Cicek O.
Published: December 2007

This study presents development and verification of a field scale compositional and non-isothermal numerical simulator for CO2 sequestration in naturally fractured systems/coalbeds. The main body of the model is three-dimensional, and four-phase mass and energy flow equations are based on compositional balances. Dual-permeability approach is used for the mathematical formulation of the problem. Single-porosity and dual-porosity approaches, subsets of the dual-permeability formulation, are considered as the second and the third approaches in the mathematical formulation of the problem. The model accounts for fluid displacement due to capillary, viscous, gravitational forces and diffusion. The field-scale simulator is developed using a fully implicit numerical solution considering the highly non-linear nature of the problem. The proposed formulation assumes (potential) nonlinearity for all the reservoir and operational parameters with respect to all primary variables identified. (2nhc+10) primary variables for each grid block are solved simultaneously, where nhc denotes the number of hydrocarbon components permissible. A direct solver is used for the resulting system of linear equations.

The present model is verified and benchmarked against two SPE Comparative Solution Projects; the Sixth SPE Comparative Solution Project: A Comparison of Dual-Porosity Simulators1, and the compositional problem of the Fourth SPE Comparative Solution Project: Comparison of Steam Injection Simulators2. In addition to these two benchmark problems, the model is tested and verified against a coal seam degasification problem from the literature3.

The present study is capable of handling the ever-changing relative effects of the various dominant forces on the establishment of fluid displacement mechanisms. The model formulation also accounts for complex fluid flow problems involving thermal effects, injection and production of fluids of different compositions as well as various composite fluid systems encountered in a given system. Having formulated sorption phenomena as a function of composition, pressure and temperature, various sorption mechanisms in coal seams would be studied by the present model.

The developed model is very flexible and capable of enveloping a number of different reservoir domains and different types of problems. As a result the present study should enable us test various hypothesis leading to improved conceptualization and modeling of fluid flow in naturally fractured geological systems.
Adding the Human Factor to Rig Anti-Collision Systems: A New Technology Explored
Authors: Whyte Jason A.
Published: December 2007

Advances in drilling rig automation have dramatically increased overall safety and efficiency by mechanizing activities traditionally accomplished by personnel working on the drill floor. However, these laborsaving machines also pose new challenges for maintaining a safe operating environment where man and machine must share the same workspace. This paper will explore a new system designed to reduce the likelihood of injuries caused by man-machine interference while also improving efficiency. The paper will discuss the methodology behind this personnel monitoring system and its potential to further improve rig safety.
Laser Drilling: Effects of Beam Application Methods on Improving Rock Removal
Authors: Parker Richard A. , Gahan Brian C. , Graves Ramona M. , Samih Batarseh , Zhiyue Xu , Reed Claude B.
Published: December 2007

Since 1997, Gas Technology Institute (GTI) has been investigating the interaction of high power lasers with different rock lithologies to determine possible applications in drilling and completing oil and gas wells. As part of an initial effort to determine the energy required to remove rock with laser beams, GTI performed a series of experiments under a US Department of Energy contract together with Argonne National Laboratory and the Colorado School of Mines. As part of this investigation, GTI identified the specific energy requirements (kJ/cc) required to remove rock from test samples of sandstone, shale and limestone using a 1.6 kW pulsed Nd:YAG laser beam. Each sample was subjected to a single exposure of the beam, and the resulting specific energy calculation was made. Results were presented in a previous SPE paper.

Additional experiments since then were performed with the same Nd:YAG laser to determine how repetitive beam applications on the same sample influence rock properties, rock removal efficiency and penetration rates. Key considerations in determining the series of tests performed included geometric pattern applications, beam overlap and spacing, focal distance changes while lasing, beam intercept angles, purging systems and thermal relaxation time between successive shots. By providing multiple overlapping beam shots, several advantages were observed that allowed faster and deeper penetration of the beam into the rock sample with no evidence of melted minerals present. This paper will describe the experimental procedures as well as pre- and post-laser data analysis to determine changes in rock properties (i.e., permeability, porosity) and effects on observed specific energy measurements for sandstone, limestone and shale samples.
Advanced Cutting Structure Improves PDC Bit Performance in Hard Rock Drilling Environments
Authors: Mensa-Wilmot Graham , Soza Robert , Hudson Kyle
Published: December 2007

Hard rock applications continue to pose serious challenges for PDC bits. Although improvements1,2,3 have been achieved in these environments, PDC bit performance is highly inconsistent and leaves much to be desired. Operational costs in such environments, due to reduced footage and/or low penetration rates (ROP), are enormously high.

This paper will evaluate the challenges of hard rock drilling. It will discuss the effects formation hardness has on drilling efficiency, and the energy level requirements associated with the different rock failure mechanisms. The definition and relationships between WOB requirements, drilling efficiency, ROP, wear flat generation and on-bottom drilling time will also be discussed.

An advanced cutting structure (ACS), which improves PDC bit effectiveness and consistency in hard rock drilling environments, will be presented. ACS improves drilling performance by re-defining and optimizing the relationships between ROP, durability and stabilization. It maximizes bit life, by slowing the PDC cutter deterioration process, without compromising ROP. This paper will describe ACS's functionality, and show the positive effects it is having on operational costs. Laboratory and field data, supporting ACS's effectiveness will also be presented.
Simulation Of Sour Gas Injection Into Low Permeability Oil Reservoirs
Authors: Thibeau Sylvain , Barker John W. , Morel Danielle
Published: December 2007

Sour gas injection into an oil reservoir is an attractive process. It provides a solution to unlock sour gas and oil reserves in other near-by reservoirs and it is an efficient EOR process, due to the high miscibility nature of the H2S and CO2 molecules.

Field evaluation of this process is classically obtained by local evaluation on a well pattern; the upscaling of the pattern; and the use of the upscaled model at the field scale.

Injectivity is a crucial issue for sour gas injection projects, since projects are due to inject sour gas volumes produced elsewhere. This is even more critical in low permeability reservoirs, where high pressure losses can be located in the near well region, leading to reaching compression and/or pumping limits.

The aim of this paper is to present the upscaling step, focusing on the sour gas injectors behaviour; to underline the limitations of single phase upscaling in a miscible environment; and to propose a consistent upscaling strategy in this context.
Multiscale Numerical Modeling of Three-Phase Flow
Authors: Ruben Juanes , Patzek Tad W.
Published: December 2007

In this paper we present a stabilized finite element method for the numerical solution of three-phase flow in porous media. The key idea of the proposed methodology is a multiscale decomposition into resolved (or grid) scales and unresolved (or subgrid) scales. In the context of subsurface flow and transport, the term multiscale usually refers to subgrid heterogeneity and upscaling. In contrast, this paper deals with unresolved physics: multiple scales are present in the solution even if the medium is homogeneous.

We use the fractional flow approach for the mathematical description of the three-phase flow equations, which leads to a global pressure equation of elliptic type, and a system of conservation laws (the saturation equations). Numerical di culties in solving these equations include: high nonlinearity, advection-dominated flow, degenerate diffusion, sharpening near-shock solutions, boundary lay- ers, and convergence to nonphysical solutions.

The multiscale formalism allows one to split the original mathematical problem into a grid-scale problem and a subscale problem. The effect of the subgrid scales is then incorporated - in integral form - into the grid-scale equations. Accounting for the subgrid effects results in a finite element method that has enhanced stability properties and is not overly diffusive. Specific original contributions of the methodology proposed herein are: (1) the formulation is applied for the first time to the three-phase flow equations; (2) the fully nonlinear equations in conservation form are used, which is essential for correctly predicting the location of shocks; and (3) a novel expression of a discontinuity-capturing technique is proposed and compared with existing formulations.

The methodology is applied to the simulation of two problems of great practical interest: oil filtration in the vadose zone, and water-gas injection in a hydrocarbon reservoir. These numerical simulations clearly show the potential and applicability of the formulation for solving the highly nonlinear, nearly hyperbolic system of three-phase porous media flow on very coarse grids.
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

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

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

Recent 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

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

This 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

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

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

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

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

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.
Strategies Coping With Challenges Of Natural Gas Development
Authors: Wang Fengjiang , Zhang Ying
Published: December 2007

In China, natural gas industry is entering a new stage of quick development. Along with the bright prospect, a number of unfavorable factors exist facing the development of this industry. From the stand point of gas development, challenges were analyzed, and strategic countermeasures coping with these challenges were proposed.
Effective Techniques for Outsourcing Engineering Projects
Authors: McGowen Harold E.
Published: December 2007

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

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

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.
Analysis of Hydrocarbon Production in a Critically-Stressed Reservoir
Authors: Miskimins Jennifer L. , Knight Constance Dodge
Published: December 2007

The North La Barge Shallow Unit (NLBSU) produces from the Mesaverde formation at depths of 2000 ft (610 m). The NLBSU exhibits four types of production behavior including fracture-dominated, matrix-dominated, fracture/matrix combination, and significantly reduced production near faults. The fracture-dominated production behavior is centralized in a structurally complex, highly stress-controlled region, which includes a horsetail splay termination of a strike-slip fault. This faulted region results in critically stressed natural fracture production.

Faults play a dual role in controlling production histories at the NLBSU. In addition to critically stress natural fracture production, several producing wells that were drilled in fault damage zones exhibit significantly reduced production performance. The presence of fault damage zones takes precedence over the occurance of natural fractures in terms of reservoir enhancement and results in poor production performance.

Knowledge of these types of production controls can aid in reservoir management throughout the life of a field.
Quantification of Uncertainty in Recovery Efficiency Predictions: Lessons Learned from 250 Mature Carbonate Fields
Authors: Sun S. Qing , Sloan Rod
Published: December 2007

The most prominent aspects of carbonate reservoirs are their heterogeneity, variable wettability and dual pore network, which collectively contribute to complex fluid flow and uncertainty in reservoir performance and recovery efficiency predictions. A review of ultimate recovery efficiency in 250 mature carbonate fields from around the world provides constraints for quantifying uncertainty in recovery efficiency predictions. Key determinants of ultimate recovery are fluid type, pore network, reservoir heterogeneity, drive mechanism and wettability. Development strategies and reservoir management techniques play crucial roles in maximizing expected ultimate recoveries for given reservoir/fluid parameters. Five main fluid type/carbonate reservoir classes, with characteristic ultimate recovery distributions and controls are: (1) heavy and viscous oil reservoirs, in which recovery factor (RF) is controlled by fluid viscosity variations, field size and application of horizontal drilling, (2) karstic/fractured carbonate oil reservoirs, in which RF is controlled by fracture intensity, matrix permeability, wettability and drive mechanism, (3) conventional carbonate oil reservoirs, in which RF is controlled by reservoir connectivity, permeability and mobility ratio, (4) organic buildup oil reservoirs, in which RF is controlled by nature and size of organic buildups and diagenetic modifications, and (5) gas/condensate reservoirs, in which RF is controlled by aquifer encroachment and condensate drop-out. Examination of actual case histories reduces uncertainty in predevelopment recovery efficiency predictions and shows what is possible in new or old fields.
Automatic History Matching in a Bayesian Framework, Example Applications
Authors: Zhang Fengjun , Skjervheim Jan Arild , Reynolds A. C. , Oliver D. S.
Published: December 2007

The Bayesian framework allows one to integrate production data and static data into a posteriori probability density function for reservoir variables (model parameters). The problem of generating realizations of the reservoir variables for the assessment of uncertainty in reservoir description or predicted reservoir performance then becomes a problem of sampling this posteriori pdf to obtain a suite of realizations. Generation of a realization by the randomized maximum likelihood method requires the minimization of an objective function that includes production data misfit terms and a model misfit term that arises from static data. Minimization of this objective function with an optimization algorithm is equivalent to the automatic history matching of production data with a prior model constructed from static data providing regularization. Because of the computational cost of computing sensitivity coefficients and the need to solve matrix problems involving the covariance matrix for the prior model, this approach has not been applied to problems where the number of data and number of reservoir model parameters are both large and the forward problem is solved by a conventional finite difference simulator.

In this work, we illustrate that computational efficiency problems can be overcome by using a scaled limited memory Broyden-Fletcher-Goldfarb-Shanno (LBFGS) algorithm to minimize the objective function, and using approximate computational stencils to approximate the multiplication of a vector by the prior covariance matrix or its inverse. Implementation of the limited memory BFGS method requires only the gradient of the objective function which can be obtained from a single solution of the adjoint problem; individual sensitivity coefficients are not needed. We apply the overall process to two examples. The first is a true field example in which a realization of log-permeabilities at 26,019 grid blocks is generated by the automatic history matching of pressure data and the second is a pseudo-field example that provides a very rough approximation to a North Sea reservoir in which a realization of log-permeabilities at 9750 gridblocks is computed by the automatic history matching of GOR and pressure data.
A Methodology for History Matching and the Assessment of Uncertainties Associated with Flow Prediction
Authors: Landa Jorge L. , Guyaguler Baris
Published: December 2007

Automatic history matching is the process of calibrating the parameters of a reservoir model by way of an automated algorithm so that the reservoir observations are close to calculated values. Automatic history matching has been heavily investigated, however a fraction of these investigations that provided ways to assess the uncertainties associated with predictions has been computationally prohibitive. In this study an approach based on response surfaces and sensitivity coefficients is presented that is not only a computationally efficient history matching process, but also provides a framework for the assessment of the uncertainties associated with prediction.

In this study, sensitivity coefficients are used to construct a response surface or a proxy for the simulator, honoring the exact data values and gradients for the simulated combinations of the parameters. This proxy is then used to guide the selection of the subsequent locations to sample for the history matching process. The accuracy of the proxy increases with the additional simulations as the algorithm progresses. The proxy revealed at the end of the history matching process is then utilized to estimate the uncertainty associated with the predictions of the future performance of the reservoir model.

The proposed method is applied to a synthetic well-testing example and a real field case for history matching and uncertainty estimation.
Identifying the Formation Failure Mechanism and Controlling Sand Production from the Upper Tuscaloosa Formation in the East Heidelberg Field Mississippi
Authors: Taylor Brent , Ringhoffer Jay , Jones Ralph
Published: December 2007

Wells previously completed in the upper Tuscaloosa and Christmas Green formations in the Heidelberg Field in Jasper County, Mississippi have exhibited a trend to produce formation sand sometime during their productive lives. Historically, traditional sand control methods have been used to control this sand production.

In order to determine formation failure mechanism, a study using a systematic process had been conducted in completions near Jasper County, Mississippi to determine the failure mechanism. Because of the success in other areas, the same process was used in the upper Tuscaloosa and Christmas Green formations in a four-well field development. The processes not only were capable of confirming the formation-failure mechanism but also were capable of controlling sand production without limiting fluid deliverability in the four wells. From this study, a hypothesis was formulated to determine the cause of formation failure.

The four-well case history will discuss the systematic approach used to confirm the formation failure mechanism and the technology that was then employed to remediate the failure mechanism and to allow these wells to be economically produced.

The discussion will cover eight completions in four wellbores in the East Heidelberg Field. Completion and stimulation technologies will be discussed, including the use of a conductivity enhancement modifier. The effect of the conductivity enhancement and surface modifier on the Upper Tuscaloosa and Christmas Formation will be shown.

The results of the study enabled proper methods to be established to control sand production.
Using Gas Injection for Reducing Pressure Losses in Multiphase Pipelines
Authors: Alvarez Carlos J. , Al-Malki Said S.
Published: December 2007

This paper presents and discusses the results of field testing gas injection into a hilly terrain crude pipeline, and applicable transient multiphase flow simulations. Field testing was conducted to evaluate the effectiveness of using gas injection into a multiphase pipeline operating under severe slugging to reduce pressure losses and increase well rates.

Transient flow simulations were used to predict pipeline pressure losses and select a line for testing. The gas injection method effectively decreased the pipeline pressure about 20 % at the inlet, allowing increased oil production from wells connected to the pipeline inlet. Predicted pressure drop reduction closely matched measurements. The drop in pressure losses is due to reduced liquid holdup in the uphill sections of the line.

Hydrostatic and frictional pressure drops need to be carefully considered to properly operate pipelines under slug flow. Injecting gas into oil pipelines experiencing slug flow can improve oil transport efficiency by reducing pressure losses, increase well rates productivity, and mitigate slug effects on receiving producing facilities. A transient multiphase flow simulator (TMFS) can accurately predict crude oil pipeline pressure drop improvement prior to gas injection.
Producing Coalbed Methane at High Rates at Low Pressures
Authors: Simpson David , Kutas Mike
Published: December 2007

In the highly productive Coal Bed Methane (CBM) "Fairway" area of the San Juan Basin of Northern New Mexico and Southern Colorado, traditional reservoir-evaluation methods have failed to approximate production levels. The reservoir seems to have the potential to produce gas at nearly the same rates at reservoir pressures of under 100 psia as it had at 1,500-1,800 psia. This observation has a significant impact on the economics of late-life investments, on the design of wellbores, on well site equipment, and on pipelines. A non-traditional approach was taken to evaluate the long-term impacts of a mix of these interventions. This mix of interventions was taken and the analysis was generally a fair indicator of specific-well response to the proposed actions.
Calculation Of Permeability Tensor Using Boundary Element Method Provides A Unique Tool To Simulate Naturally Fractured Reservoirs
Authors: Teimoori A. , Chen Z. , Rahman S. S. , Tran T.
Published: December 2007

This paper presents a numerical model to calculate effective permeability tensor in naturally fractured reservoirs. Darcy's law and Navier-stoke's equation are used to formulate fluid flow in rock matrix and fractures, respectively. Fractures of different scales based on their length are considered. Short fractures are considered as an enhancement of matrix permeability by applying the interface boundary condition. Long fractures intersecting more than one block are treated as a source/sink in the corresponding blocks. Fluid flow in porous matrix around the medium and long fractures is modeled by Poisson's equation. Periodic boundary condition is applied on the grid-block boundaries to calculate the elements of effective permeability tensor. The model has been validated against analytical results and applied to a number of cases where arbitrary fractures of different sizes are assumed within the grid-blocks.
New Environmentally Friendly Oil-Based Stimulation Fluids
Authors: DeVine C. S. , Wood W. D. , Shekarchian M. , Hunnicutt B. R.
Published: December 2007

The lab and field development of an environmentally friendly liquid diesel substitute-based (DiSub) system for completion and stimulation, with properties similar to or exceeding those achieved with diesel, will be discussed.

The chemical evolution of the DiSub system and properties of the fluid including rheology, break and conductivity testing, and toxicity data will be presented. The application of the system in a field situation is described.

Since the inception of hydraulic fracturing, oil-based fracturing and completion fluids have been used. Motivations for using these systems include: formation sensitivity to water; water retention by the formation, such as water blocks; and the inability of low-pressure oil productive formations to unload water. Oil-based fracturing designs have historically required complicated procedures to successfully execute a fracturing operation. Fluid compositions used did not consistently produce stimulation fluids with optimum viscosity or transport properties. Drilling and completion activities in the North Sea, deepwater Gulf of Mexico, Alaska, and Canada provided the impetus to develop innovative environmentally-friendly completion techniques and chemistries.

The DiSub system provides a cost effective and environmentally-friendly stimulation fluid. The system is within most global environmental standards and has been approved and used in the North Sea due to its excellent properties, like zero aromatic content, low aquatic toxicity and excellent biodegradability. This makes it a major improvement over the use of diesel and mineral oils, for both humans and the environment. Exposure hazards and the variability of the previously used diesel and/or lease crude are eliminated.