bluuebunny/crossref_metadata_2025_split huggingface dataset:
Pt. McIntyre: A Case Study of Gas Enrichment Above MME
Authors: Moulds T. P. , McGuire P. L. , Jerauld G. R. , Lee S-T. , Solano R. 
Published: December 2007

Abstract
This paper describes an evaluation to determine the optimum enrichment for an enriched gas drive project at the Pt. McIntyre field, Alaska. The miscible injectant (MI) at Pt. McIntyre displaces oil in a multi-contact miscible (MCM) displacement that is achieved through a combined condensing and vaporizing (C-V) mechanism. A range of MI compositions, varying from minimum miscible enrichment (MME) to substantially above MME, is available to the project.
Field-scale numerical simulation studies show that incremental oil recovery is nearly doubled when using the richest available MI composition. This is consistent with previously reported results for numerical simulation of field scale WAG processes that show significant improvement in recovery with continued enrichment. In this paper we further develop the mechanistic understanding of enrichment above MME on the recovery process.
Multiple contact mixing cell models show that continued enrichment above MME increases the effectiveness of both the condensing and vaporizing behaviors in the development of miscibility. In systems that are effectively non-dispersive, such as laboratory slimtube experiments, enrichment above MME has little impact on recovery. However, in field scale systems dispersion dominates MCM process efficiency, in this case enrichment above MME provides a powerful improvement in the MCM mechanism that substantially mitigates the deleterious effects of dispersion. We show how compositional core data from an MI swept interval provides insight to the recovery mechanism and confirmation of the impact of dispersion at field scale.
Previous studies into MI enrichment have reported that for a four-component system the mechanism changes from C-V to purely condensing as the enrichment level approaches first contact miscibility (FCM). We show that with the addition of a small amount of heavy component the C-V behavior is retained with increasing enrichment until transition into FCM. This makes it unlikely that a transition to purely condensing mechanism will occur in real reservoirs.
The impact of gas-oil relative permeability dependence on IFT was assessed. It is found that relative permeability modification is of secondary importance compared to the recovery benefits due to enhanced compositional performance using richer MI.
Case Studies of Uncertainty Analysis in the Seismic to Reservoir Simulation Workflow
Authors: Sahni Akshay 
Published: December 2007

Abstract
This paper presents the work of a multidisciplinary team of earth scientists and engineers to develop an offshore heavy oil field while accounting for uncertainties in the geological and reservoir simulation models. The field is located in shallow waters and has oil ranging in viscosities from 20cp to 200cp. The depositional environment is a fluvial meandering river system where the sands are thin and disconnected. The field has a handful of appraisal wells and 3-D seismic data, along with extensive measurements of rock-fluid properties and geochemistry analysis. Some of the appraisal wells also have good quality DST and MDT data which was used to constrain the geological model.
The workflow comprised of constructing a geological model using deterministic geo-bodies identified from analysis of acoustic impedance and stochastic sands in areas of poor seismic quality or below the threshold of seismic resolution. These stochastic sands were tied to well control and simulated using a sequential indicator technique. Various field development scenarios were considered, including inverted five spot and nine-spot pattern waterfloods, along with application of horizontal wells. Development scenarios and predictions incorporated uncertainties in water oil contact's, net-to-gross, oil viscosities, relative permeability, residual oil saturations, injectivity and skin factors. The use of experimental design techniques and parallel simulation enabled the team to capture the range of uncertainty in subsurface and engineering parameters while keeping computational times manageable. The paper discusses some of the key uncertainties and challenges in bringing this and similar reservoirs to development.
Subsurface Uncertainty Management in the Harweel Cluster, South Oman
Authors: O'Dell Mike , Lamers Edwin 
Published: December 2007

Abstract
There has been a string of exploration successes the past five years in discovering some 350 million m3 (2 billion barrels) of oil in the Harweel Cluster in South Oman. This oil is deep, at high pressure, comes with high GOR, and the fluids contain 15% CO2 and 5% H2S. Of the nine Precambrian carbonate reservoirs, six are lithostatically pressured and three are hydrostatic. The Harweel Cluster is more than 70 km from existing infrastructure. If gas can be re-injected, miscible displacement is expected in many of the reservoirs. The Harweel Cluster is one of Oman's major opportunities for "green field" oil development.
There is a large degree of subsurface uncertainty in gross rock volume and Oil-Water-Contact, reservoir architecture, faults and fractures and reservoir compartmentalization, degree of dolomitization, permeability level and heterogeneity, fluid properties, and so on. However, little is known about the scale and relative importance of each of these uncertainties. Some uncertainties, such as compositional grading, might turn out to be more important than anticipated when evaluating development options due to non-linearities and dependencies.
Analyzing the effects of all uncertainty combinations in all reservoirs is not a realistic option. Therefore a structured scenario based approach has been developed to analyze and assess all potential factors influencing recovery schemes, reserves and productivity. After evaluating the range of possible values and calculating the impact of each uncertainty, realizations were created to represent the range of possible values in each new reservoir. Field scale equation-of-state models were used to simulate both primary depletion and gas re-injection. Development scenarios were optimised for each discrete realization. The resulting reservoir models serve as a basis for the development concept selection and the subsequent Field Development Plans.
Evaluating Well Performance and Completion Effectiveness in Hydraulically Fractured Low-Permeability Gas Wells
Authors: Cramer David D 
Published: December 2007

Abstract
Hydraulic fracture stimulation often dictates the economic outcome of wells completed in low permeability gas reservoirs. Attempting to understand well performance - the rate and pressure behavior of a well over its productive life - provides the opportunity to discover the elements driving stimulation and completion effectiveness. This paper demonstrates the integrated use of practical reservoir engineering methods to evaluate well performance, identify flow regimes and distinguish between reservoir and completion induced behavior in low-permeability hydraulically fractured gas wells.
Clean-up of Water Blocks in Low Permeability Formations
Authors: Mahadevan Jagannathan , Sharma Mukul M. 
Published: December 2007

Abstract
Water-blocked low permeability gas formations with drawdown pressures comparable to capillary entry pressures can take a very long time to clean up. The clean up of water blocks in gas wells occurs in two regimes: displacement of the fluids from the formation followed by vaporization by the flowing gas, which becomes under-saturated as the pressure decreases.
This work aims to study the effect of rock permeability, wettability, temperature, drawdown and surfactants on the clean up of cores containing brine. The effectiveness of using solvents for cleanup under different conditions has been evaluated by comparing gas relative permeabilities with and without methanol.
Gas displacement experiments were conducted on cores fully saturated with brine. The gas relative permeability increases with pore volumes of gas injected for long periods of time (up to 100,000 PV) at ambient temperature. The addition of methanol, increasing temperature and increasing core permeability resulted in faster cleanup after about 50 to 100 PV of gas flow. The change of wettability of the rock from water-wet to oil-wet also resulted in faster recoveries in gas relative permeability.
Our observations show that the clean up of water-blocks can be improved by: 1. Influencing the displacement of brine, i.e. by changing the wettability and, 2. By increasing the rate of vaporization by introducing volatile solvents such as methanol. It is found that changing wettability also has an impact on the rate of vaporization of the brine and methanol.
The study quantifies the effects of factors such as rock permeability, wettability, surface tension, and temperature on gas relative permeability. The results of this study will help in selecting strategies for clean-up of water blocks created due to various operations such as drilling, acidizing and fracturing, and making recommendations for the use of surfactants or solvents for well treatments to remove water blocks.
Optimal Appraisal Well Location Through Efficient Uncertainty Reduction and Value of Information Techniques
Authors: Haskett William J. 
Published: December 2007

Abstract
Successful exploration, efficient appraisal, and profitable extraction are the three phases of any E&P project; each in turn is dependent upon the prior. However, efficient appraisal of newly discovered resources sets the stage for maximizing project profitability and managing risk. The goal of an efficient appraisal program is to achieve maximum reduction in uncertainty with minimal cost. The more certain a company is regarding the size and scope of a particular project, the better decision it can make on its development case selection, the greater the possibilities for downside risk mitigation, and the more efficiently it can manage its entire development portfolio. The end of the appraisal period occurs when further uncertainty reduction would not materially effect the principle development decisions, or at the point at which the downside project risk becomes acceptable to the company.
Specific appraisal locations should typically be selected on their ability to provide the greatest overall reduction in project uncertainty. Project uncertainty is tied directly to the variance of the outcome distribution and can be summarized by the uncertainty range, which utilizes the commonly understood distribution descriptors. An understanding of the difference between discrete learning events and population sampling learning is critical to the estimation of uncertainty reduction.
Potential appraisal locations will contribute to a reduction in uncertainty given either failure or success. Competing appraisal locations may be compared through their propensity for uncertainty reduction using standard value of information techniques (VoI). This quantitative method provides an assessment of the relative value of uncertainty reduction of competing or prioritized development locations, and may be extended within a multi-prospect situation to rank competing prospects within a commonly constrained business opportunity.
Measurement of the Two-Phase Gas Slippage Phenomenon and Its Effect on Gas Relative Permeability in Tight Gas Sands
Authors: Rushing J. A. , Newsham K. E. , Van Fraassen K. C. 
Published: December 2007

Abstract
This paper presents results from a laboratory study of the two-phase gas slippage phenomenon and its impact on effective and relative gas permeabilities in tight gas sands. Core samples from the Bossier tight gas sand play in the Mimms Creek Field in Freestone Co., TX were evaluated at water saturations ranging from 5 to 40 percent. We also investigated the effects of net overburden pressure and reservoir temperature on this phenomenon. Results from our study indicate that, if two-phase gas slippage is not considered in the laboratory measurements, then we may overestimate gas relative permeabilities.
Disaster Insurance Using Portfolio Management Techniques
Authors: DuBois James R. , Quarles Andrew I. 
Published: December 2007

AbstractThere is a growing body of literature in our industry that addresses the use of portfolio management techniques to find "optimum" mixes of projects that meet company goals while managing risk. These investigations usually start by describing "risk" in some manner, then proceed to illustrate how combinations of properties can be chosen that minimize this risk function subject to the other goals of the company. The probabilities of meeting individual metric targets in discrete time frames can and should also be quantified.This type of analysis is valid and useful, and forms the backbone of project portfolio management. However, when dealing with risk and probability concepts it is easy to lose sight that specific events will occur in time, and that the portfolio must include enough flexibility to allow reaction to and recovery from these events.Specifically, acceptable portfolio results may depend on a small number of projects performing at a certain level. Because the chance of these important projects not performing at this level may be relatively small, the risk is deemed "acceptable". If one of the projects subsequently fails to perform, what was once "acceptable risk" can become an exercise in salvaging a year or even saving a company.In this paper, we will show how portfolio management techniques can be used to plan a portfolio robust enough to recover from a potential future disaster. We will demonstrate with examples how the techniques can lead us to make investment choices today that might not be obvious if projects are evaluated solely using their expected values. These choices, if made judiciously, can provide insurance against possible future downside.Portfolio analysis is a powerful technique, with applications far beyond the standard risk-reward exercise. We will show here some examples of how it can be used to provide insight into the practical business questions that truly concern company management.
Petroleum Engineering Education and Training Initiatives across Asia Pacific
Authors: Lloyd P. M. , Ronalds B. F. 
Published: December 2007

Abstract
The paper summarizes the discussion and key outcomes of the Asia Pacific Colloquium on Education and Training for the Petroleum Industry, held in Bali in September 2002. This Colloquium was a little different from the two previous events in this series because it not only tried to define the skill sets of the engineers whom the industry would like to see graduate, but it also looked at keeping skill sets current during their careers.
We believe that the three Asia Pacific Petroleum Engineering Colloquia over the past six years have played a pivotal role in bringing industry and educators together to debate and reach consensus on future education and training needs. The fruits of these labors were evident in this third colloquium. However, "engineering certification" is an issue which we anticipate will become increasingly important in the region in the next few years, and effort should be put in this area so that the professional societies can have ownership.
Building Reservoir Models Based on 4D Seismic & Well Data in Gulf of Mexico Oil Fields
Authors: Bogan Catherine , Johnson Daniel , Litvak Michael , Stauber Doug 
Published: December 2007

Abstract
A general methodology has been developed for building and history matching reservoir models based on 4D seismic, petrophysical, and production data. The methodology consists of: construction of structural maps of different reservoir zones; building 3D facies models; geostatistical construction of 3D volumes of reservoir properties (porosity, net-to-gross ratio, permeability) constrained by seismic and well log data; construction of fluid flow barriers; and matching of seismic attribute changes over time.
A procedure has been developed for building confining surfaces of the reservoir zones matching well markers and velocity maps. Object based modeling tools have been applied for the construction of the 3D facies models constrained by seismic and well data, and consistent with depositional environment. The construction of the 3-D volumes of the reservoir properties is based on latest achievements in rock mechanics - sim2seis correlations, which correlate seismic attributes (for example, acoustic impedance AI) to porosity, net-to-gross ratio, pressure, water & gas saturation and rock properties. The procedure has been developed to calibrate sim2seis correlations based on well log and pressure data. The procedure is applied for effective porosity definition, in two parts. First, correlating 3D seismic AI with well logs averaged over the corresponding model cells derives an effective porosity trend. Second, geostatistical modeling tools are applied to define the 3D effective porosity volume constrained by well log data and the effective porosity trend. A new procedure has been developed for the construction of the fluid flow barriers from 4D seismic.
The developed methodology has been applied in several Gulf of Mexico oil fields. It has been demonstrated that: a reasonable history match can be achieved without any adjustments of the reservoir models, and that fluid flow barriers derived from 4D seismic significantly improve history matching results. A good match of predicted results and field measurements from recently drilled wells (suggested by reservoir modeling) has demonstrated the prediction capabilities of the constructed reservoir models.
The Role of Cut-offs in Integrated Reservoir Studies
Authors: Worthington Paul F. , Cosentino Luca 
Published: December 2007

Abstract
There have been many different approaches to quantifying cut-offs, with no single method emerging as the definitive basis for delineating net pay. Yet, each of these approaches yields a different reservoir model, so it is imperative that cutoffs be fit-for-purpose, i.e. they are compatible with the reservoir mechanism and with a systematic methodology for the evaluation of hydrocarbons in place and for the estimation of reserves. These different requirements are accommodated by basing the quantification of cut-offs on reservoir-specific criteria that govern the storage and flow of hydrocarbons. In so doing, particular attention is paid to the relationships between the identification of cut-offs and key elements of the contemporary systemic practice of integrated reservoir studies. The outcome is a structured approach to the use of cut-offs in the estimation of reserves. The principal benefits of a properly conditioned set of petrophysical cut-offs are a more exact characterization of the reservoir with a better synergy between the static and dynamic reservoir models, so that an energy company can more fully realize the asset value.
Integrated Fractured Reservoir Characterization and Simulation: Application to Sidi El Kilani Field, Tunisia
Authors: Laribi M. , Boubaker H. , Beck B. J. , Chen H-K. , Amiri-Garroussi K. , Rassas S. , Rourou A. , Boufares T. , Douik H. , Saidi N. , Ouenes A. 
Published: December 2007

Abstract
Sidi El Kilani field produces oil from a Type 1 fractured carbonate reservoir. The field has produced 42 mmstb oil since first production in 1991, and has consistently out-performed expectations. As with many fractured reservoirs it has proved difficult to describe and model the fracture distribution or to predict or control water breakthrough. Prior to this study three out of nine boreholes in the field encountered tight rock and are dry holes.
This integrated study used geophysical, geologic, and engineering data simultaneously to improve the reservoir description. The reservoir model was proven with the successful completion of a 400m horizontal sidetrack of one of the dry holes. The successful characterization of the fractures was mostly due to the extensive use of 3D seismic data. Seismic impedance, velocity, density and coherence were used as input in the integrated fracture modeling process. Seismic data was also used to derive geologic drivers. In all nineteen geologic and seismic drivers were correlated, using artificial intelligence tools, against a fracture porosity indicator computed from conventional logs. 3D permeability models were then derived using a whole core porosity-permeability relationship, and input into a reservoir simulator. The production history of most wells was readily matched.
The drilling results indicate that the 3D fracture models can be used successfully to locate highly fractured areas. This was possible by using an integrated fracture modeling approach. None of the individual geologic and geophysical drivers gave a clear and accurate description of the 3D distribution of the fractures. Their simultaneous use with a fracture porosity indicator and artificial intelligence tools revealed the complexity of the reservoir and its fracture network.
Integrating Short-Term Pressure Buildup Testing and Long-Term Production Data Analysis to Evaluate Hydraulically-Fractured Gas Well Performance
Authors: Rushing J. A. , Blasingame T. A. 
Published: December 2007

Abstract
This paper presents an integrated approach for evaluating the post-fracture performance of gas wells completed in tight gas sands. Our technique focuses on a methodology for evaluating the stimulation effectiveness of hydraulically fractured gas wells. Rather than relying on a single evaluation technique, we integrate short-term pressure buildup testing with long-term production data analysis using decline type curves. We illustrate the applicability and efficacy of our technique with examples from more than twenty wells completed in tight gas sands. The results of our paper also demonstrate the value and function of short-term pressure buildup tests performed in tight gas sands.
Hydraulic Fracture Mapping of the High-Temperature, High-Pressure Bossier Sands in East Texas
Authors: Griffin L. G. , Sullivan R. B. , Wolhart S. L. , Waltman C. K. , Wright C. A. , Weijers L. , Warpinski N. R. 
Published: December 2007

Abstract
Anadarko Petroleum Corporation has conducted a study to improve hydraulic fracturing and field development in the Bossier sands in the East Texas Basin. As part of this study, hydraulic fracture mapping was performed with microseismic imaging on three wells completed in the Bossier sands.
Microseismic fracture mapping is an emerging technology to optimize development of hydraulically fractured reservoirs. This paper demonstrates the use of microseismic mapping under high temperature (300°F) conditions. It also demonstrates how the directly measured results can be implemented to calibrate a 3D fracture growth model.
The study shows mapping results for waterfracs and hybrid fracture treatments (which utilize slickwater to generate the fracture geometry and crosslinked gel to transport the proppant) in the Bossier. Fracture azimuth was fairly consistent for the three wells and fit with earlier surface tiltmeter mapping result in this area. Fracture growth asymmetry was observed and is discussed in the paper. Payzone coverage was generally good but could be improved and created fracture lengths varied significantly between wells.