bluuebunny/crossref_metadata_2025_split huggingface dataset:
Determination of Methane Emissions From Crude Oil Stock Tanks
Authors: Newsom Vick L. 
Published: December 2007

Abstract
There are approximately 250,000 tank batteries currently in operation in the US exploration and production (E&P) industry. Most of these batteries do not have any type of control system on them to capture the organic vapors generated by breathing losses, working losses and flashing losses. If the pressure drop from the low pressure separator to the stock tank is greater than a few pounds, then the potential for significant emissions due to flashing losses is present.
Due to the perception by the Clinton Administration that global warming is an issue that needs to be addressed by the US industry, the methane emissions from stock tanks will come under increased scrutiny.
This paper discusses a method for determining methane emissions from stock tanks and how controlling these emissions can aid industry in its work with the Environmental Protection Agency on the Natural Gas STAR program.
The Competing Influence of Technology, Depletion, and Economics on Petroleum Drilling Productivity: How Persuasive is the Evidence in the Gulf of Mexico Outer Continental Shelf?
Authors: Iledare Omowunmi O. 
Published: December 2007

Abstract
The purpose of this paper is to apply a region-specific- hybrid model of oil and gas reserve additions to determine whether the negative impact of depletion on the finding rate of new reserves has been more than offset by the positive effects of technical progress and economic incentives in the US Gulf of Mexico OCS region. Our model results confirm expectation of diminishing returns in the rate of change of drilling productivity with respect to basin maturity. We also found strong evidence, to suggest that as technology improves over time, better drilling choices are made and the rate of change of drilling productivity with respect to incremental drilling rises with time. Overall, we found strong statistical evidence to suggest that the positive influence of technical progress and economic incentives on drilling productivity has been strong enough to offset the negative impact of resource depletion on the finding rate of oil and gas reserves in the US Gulf of Mexico OCS during our study period.
Best Practices in Project Evaluation and Influence on Company Performance
Authors: Schuyler J. R. 
Published: December 2007

Abstract
How do respected companies perform their project evaluations? Do better project evaluation practices and decision policies lead to better company performance? As an initial step to find out, a "Decision and Evaluation Best Practices Survey" has been conducted. Twenty-one companies are participating, thus far, providing a cross section of the petroleum industry. The survey results form a nascent "best practices" database. The author reflects upon the survey data and his experience to describe characteristics of good evaluation management. Because resource allocation decisions are so important, policy and evaluation practices should receive attention comparable to the other technical disciplines. Recent trends in evaluation techniques are discussed, including an increased use of decision analysis.
Hybrid Risk Modeling, Synthesizing Deterministic, Stochastic, and 3-D Geocellular Techniques: Example from Jackson Field, Eromanga Basin, Queensland, Australia
Authors: Holtz Mark H. , Yeh Joseph , Hamilton Douglas S. 
Published: December 2007

Abstract
Risk is inherent in the outcome of all reservoir characterization oil volumetries. This risk comes from the very small sample of information relative to the total reservoir volume and the error in data measurement. To incorporate the risk into reservoir characterization, some qualitative aspects are best modeled deterministically, whereas other data can be modeled statistically. Probability distributions were generated for original oil in place (OIP), original mobile OIP, original residual OIP, and remaining mobile OIP by combining geologic characteristics modeled deterministically using a 3 -D computer technique with statistical probability functions of petrophysical attributes.
The risk-assessment model applied in this study integrates wireline-derived petrophysical data with results from 3-D geocellular reservoir computer modeling. Model development is based on deterministically setting the net-pay volume derived from geologic flow-unit geometry and risk assessing the variability of the petrophysical characteristics within the flow unit. The net-pay volume is a result of the sum of the cell volumes meeting the pay cutoff criteria within the gross volume of a given flow unit. Wireline petrophysical properties have been analyzed within the flow-unit structure. Petrophysical properties were statistically analyzed to determine the best probability function that described their variability. The Weibull probability function was found to best describe the frequency distribution of porosity, whereas the gamma function best models initial water saturation and bypassed oil saturation. Monte Carlo stochastic simulation was then used to combine the deterministically derived net-pay volume with the petrophysical probability functions to generate oil-in-place density distributions. The resultant skewed nature of the OOIP frequency distribution is best modeled by a gamma function.
Risk assessment verifies that the 3-D geocellular model OOIP results are a good representation of proved and probable (2P) volumes. Geocellular model results are virtually identical to the mean value derived from stochastic simulation. Because of the skewness of the OOIP distribution, the mean OOIP is a conservative value; therefore, the 3-D geocellular model OOIP can also be considered conservative. The mode is nearly 10 percent larger than the mean, displaying a strong probability of larger volumes and quantifying the upside of the 3-D model.
The Timing of Investment in E & P: Uncertainty, Irreversibility, Learning, and Strategic Consideration
Authors: Dias M. A. G. 
Published: December 2007

Abstract
This paper analyzes the problem faced by an oil company with investment rights over the tracks subject to relinquishment requirements, which limit the time the company can hold the tract before developing it. Some concepts of the modem Real Options Theory are described briefly, with focus on the timing aspects: economic uncertainty and irreversibility incentive the learning by waiting, and delays the investment; technical uncertainty incentives the learning by doing, and generally speeds investment up. The technical uncertainty (existence, quality and volume of reserves) is dominant for the exploratory investment decisions, whereas the economic uncertainty (oil/reserves prices and costs) is dominant for the development decisions.
The arrival of technical information in the exploratory phase comes from two sources with opposite effects on the investment start up: information from the company itself exploration, and information from the neighbors tracts exploration. The second effect is one strategic aspect, and can be modeled by the Game Theory, usually as a non-cooperative game between the tracts owners, in the same geographical area. This non-cooperative game creates an another waiting effect: many companies can prefer to wait some of the neighbors investments (and get some "free" information) before start their own (and expensive) exploratory investment.
Some results for the development investment decisions are presented, using the Paddock, Siegel & Smith model, with the Barone-Adesi & Whaley analytic approximation, through an Excel spreadsheet. Also are presented some results from the interactions of two sources of economic uncertainty: the reserves value uncertainty and the development cost uncertainty. Although this effect can be small, the cost uncertainty lowers the total economic uncertainty (reducing the value of the option to defer), since the cost fluctuations are positively correlated with the oil/reserves prices, and the cost uncertainty is lower than price uncertainty. Some conclusions and suggestions are presented.
Development of Marginal Fields through Technical and Commercial Innovation - A Case History from the UK North Sea
Authors: Rattey R. P. , Suller J. N. 
Published: December 2007

Abstract
The biggest development in the North Sea for a decade has attracted industry attention as one of the most innovative projects to date. Seven economically marginal fields with different owners and different hydrocarbons have been brought together to create the £1.6 billion Eastern Trough Area Project (ETAP). Innovation on both technical and commercial fronts has been created by an unprecedented level of cooperation between companies. This paper outlines the basis of the project and the approach adopted to its formulation which resulted in novel technical and commercial solutions.
The challenge for today's North Sea, with ever decreasing field size, is to reduce development costs/bbl to acceptable levels and to do this through working the two available levers: cost and the number of barrels. The ETAP solution to reduce cost and add barrels is to combine small fields into a single project with development cost/bbl similar to a single giant field, but with the reservoir risk mitigation inherent in accessing multiple independent reservoirs. This approach created many hurdles, both technical and commercial, and has stimulated innovative solutions.
Technical hurdles include the need for long distance sub sea multiphase tiebacks in excess of 35 Km which have innovative chemical control and multiphase metering. Commercially, the project presented a major challenge as all parties agreed that a conventional unitisation of all the fields into unified ownership interests was neither practical or desirable in light of the range of fluid types and reservoir uncertainty. Accordingly a structure was developed to a) share Capital and Operating costs equitably, b) provide for production rights and production allocation and c) encourage full utilisation of the shared facilities.
The significant cost savings needed to make ETAP viable were largely achieved in the conceptual design phase by designing shared and centralised facilities for both oil and gas field management. In the current project execution phase additional cost savings are being delivered through further application of "alliance contracting" with the contractors for design, fabrication and installation of the facilities and for the development drilling.
A Control Volume Scheme for Flexible Grids in Reservoir Simulation
Authors: Verma Santosh , Aziz Khalid 
Published: December 2007

ABSTRACT
The commonly used Cartesian and hybrid local grid refinements have the disadvantage that the base grid is always Cartesian, which makes it difficult to align along reservoir heterogeneities. Also, the locally orthogonal Voronoi and A;-orthogonal perpendicular bisector (PEBI) grids are only useful for isotropic or limited anisotropic permeability distributions. The finite-difference approach proposed in this paper overcomes limitations of existing flexible gridding schemes in modeling full, anisotropic and asymmetric permeability tensors and permeability heterogeneity. The new scheme assumes uniform properties inside control-volumes and it can be used for control volumes formed around vertices of triangles in two-dimensions and tetrahedrain three-dimensions. It can thus be used with Voronoi grids in two-dimensions, and median (i.e. CVFE) and boundary adapting grids (BAG) in two- and three-dimensions. Applications of Voronoi grids in three-dimensions are limited due to geometrical considerations. The proposed method can also be used with grids constructed to align along major reservoir heterogeneities, wells and streamlines. Several applications of this method for two- and three-dimensional problems are presented.
Calculating the Impact of Fluid Migration on Steamflood Operations
Authors: Chiou C.S. , Weinstein H.G. , Miller D.D. , Eggenschwiler M.E. , Djabbarah N.F. 
Published: December 2007

Abstract
Operating decisions for steamfloods can be improved by accounting for fluid migration across pattern boundaries. a new parameter, called Fluid Migration Index (FMI), is based upuon simplified steamflood material balance considerations and can easily be calculated from field injection and production data. This parameter can be used to correct individual pattern performance. The validity of the fluid migration index was further checked with available subsurface information. Reservoir simulation, with a newly-designed internal accounting system that can track fluid movements across pattern boundaries, was used to corroborate the FMI concept and also to calculate true allocation factors of well production from surrounding patterns. Simulation results show improved accuracy in calculating fluid migration and evaluating pattern performance. It is anticipated that using the results of this paper will improve current steamflooding policies and optimize the design of future projects.

Introduction
In steamfloods with repeated patterns, it is frequently assumed that fluid is confined within the pattern such that there is no fluid migration across pattern boundaries. This assumption is not always valid. Fluid migration was reported in the Kern River and Deerfield steamfloods.1,2 Fluid migration has also long been recognized in the South Belrdige steamflood.3 Significant fluid migration from the structural crest of the Tulare formation to the flank has resulted in discrepancies in pattern oil recovery calculations between allocated production data and open-hole logs from infill wells. Reservoir pressure gradients due to dip, reservoir heterogeneities, and local variation in the injection and production conditions during the steamflood operation are probable causes for fluid migration.
If fluid migration across a pattern boundary is not properly accounted for, the commonly used pattern performance indicators, such oil/steam ratio and oil recovery, could be deceiving. Investment and operating decisions that are based on these misleading indicators could be in error. Therefore, there is a need to quantify the fluid migration and develop a methodology to evaluate its impact on steamflood operations.
Peake4 estimated the amount of fluid migration form a 16-pattern pilot study based on a simple steamflood material balance. Production data from the offset pilot provided evidence that the magnitude of the oil migration estimate was reasonable.
A new parameter, Fluid Migration Index (FMI), is introduced in this paper to quantify fluid migration. The validity of the parameter was checked with available openhole logs from infill wells. Reservoir simulation is coupled with analytical techniques to track fluid movements and characterize producing well performance. The objectives of the simulation study are to help understand the effects of fluid migration across field patterns and develop new procedures that better quantify these effects.
Recognition and Development of Low-Resistivity Pay
Authors: Worthington Paul F. 
Published: December 2007

Abstract
In unfractured reservoirs, low-resistivity pay zones can usually be identified with one or more of the following: laminated reservoir/non-reservoir sequences, formations with multi-modal pore-size characteristics, sediments with anomalously high surface area, and reservoir characteristics that extend beyond the range of applicability of interpretative algorithms, e.g. reservoirs containing very fresh formation waters. In all these cases, dry oil has been produced in the presence of high interpreted water saturations, in many different parts of the world. It is therefore important to have a generalised facility for recognising low-resistivity pay as early as possible in the life of a prospect.
A systematic procedure is described for the identification of low-resistivity and low-resistivity-contrast pay zones in primary reservoirs. The approach acknowledges that a reservoir rock is a coupled physicochemical system, the method is generic and robust, it is conceptually simple, and it is structured in a manner that is easy to understand. The scheme is modular and it is arranged hierarchically to reflect maturing data scenarios. Therefore it can be progressively refined during the appraisal and development stages. The essence of the method is the definition and calibration of reliable interpretative procedures through quality-assured reference data from key wells by admitting only validated reservoir characteristics. Examples illustrate how failure to do this can result in much loss of value.
The principal thrust is to facilitate the re-evaluation of other wells within the same reservoir system without the need for additional logging programmes. The proposed interpretation scheme also constitutes a basis for the incorporation of new logging technology when this becomes established. The end-product is a flexible petrophysical interpretation scheme for these complex reservoirs that benefits from cost-effectiveness, portability, a higher degree of exactness and consequently a reduced uncertainty.
Field Experience with the Maraflood Process
Authors: Gogarty W.B. , Davis J.A. 
Published: December 2007

Introduction
This paper reviews field test experience with the Maraflood* oil recovery process with special emphasis on the evaluation of field testing in the Pennsylvanian aged Robinson sands of Southern Illinois. The Maraflood process utilizes a slug of micellar solution process utilizes a slug of micellar solution to displace in situ crude oil. This slug is, in turn, displaced by a bank of fluid of control mobility (referred to as mobility buffer). The flooding sequence is completed with the injection of drive water.
Detailed discussions on the nature of micellar solutions and laboratory experiments evaluating their performance have been previously reported. Initial field testing previously reported. Initial field testing was started in 1962 in the Robinson sand. Since that time, eleven tests have been reported. Six of these tests have been or are being carried out in the Robinson sand. Two other tests are in progress in Illinois, one in the Kirkwood or Cypress sand and the other in the Aux Vases sand. Three tests have been completed or are underway in Pennsylvania.
The evolution of micellar solution flooding is reviewed in this paper with examples from six tests carried out in the Robinson sand. Test experience on these six tests is given first. Next, the development of the test pattern philosophy is discussed as covers the ten-year testing period. Then the progress of design and evaluation method is described by using examples from specific tests. Finally, economics are considered as related to fluid and project costs in the Robinson sandstone.

Test Experience
The micellar solutions used in all tests consisted of a surfactant, hydrocarbon and water. Small quantities of a cosurfactant and electrolyte were also added in most tests. Table 1 shows the compositional ranges of three categories of micellar solutions which have been developed for field use. The designation of oil-external and water-external in the table indicates the non-dispersed phase of the micellar solution. Systems falling within the three categories of Table 1 have been studied extensively in the laboratory.
Hydraulic Fracturing Technique for Low Permeability Coalbed Methane Gas Reservoirs
Authors: Zhao Jinzhou , Guo Dali , Hu Yongquan , Chen Wenbin , Tian Jidong , Ji Lujun 
Published: December 2007

Abstract
Coalbed methane is an unconventional gas resource. Although the resource is successfully developed in a few coal-bearing basins that are of the type of hydraulic seal with a middle or high permeability at shallow depth, the most methane resource in coal seam with pressure seal at shallow or deep are still not exploited by means of the existing technique. This paper describes the hydraulic fracturing technique for low permeability coalbed methane gas reservoirs, including the research & selection of oil base gel fracturing fluid system; real-time simulation of 3D fracture propagation; technology of controlling the fracture height growth & promoting the fracture length propagation; production performance prediction and optimal design of hydraulic fracturing treatment. A set of optimal design software for Windows 95 is developed for hydraulic fracturing in low permeability coalbed gas reservoirs based on the above-mentioned technique. Successfully treatment cases of applying the sophisticated technique in coalbed methane gas reservoirs of Middle China and North China are given in this paper.
Improvements in Perforating Performance in High Compressive Strength Rocks
Authors: Smith P. S. , Behrmann L. A. , Yang Wenbo 
Published: December 2007

Abstract
The productivity of wells damaged during drilling is directly dependent on the depth of the damage and the performance of the perforating guns. If the perforations by-pass the damaged zone then the well will have a low mechanical skin. Conversely, if the depth of damage is greater than the perforation length, the skin factor will be much higher, especially when the drilling damage is severe. While we normally associate drilling damage with low strength rocks, there are reported hard-rock fields with extensive drilling damage.
The performance of shaped charges is significantly affected by the compressive strength of the rock to be perforated; consequently, the ability to bypass drilling damage in formations with high rock strength is reduced. Previously reported work1,2 has shown a 75% reduction in total target penetration, compared to API Section I, in rock with an unconfined compressive strength of approximately 25,000 psi.
This paper describes the development and field testing of alternative charge designs aimed at improving performance in high compressive strength formations. So that the adverse effects of drilling damage can be reduced, computer simulations and laboratory tests showing the improvements achieved are presented. Field testing of the new charges and results achieved are shown.