bluuebunny/crossref_metadata_2025_split huggingface dataset:
Geological Sequestration of Carbon Dioxide in a Depleted Oil Reservoir
Authors: Krumhansl J. , Pawar R. , Grigg R. , Westrich H. , Warpinski N. , Zhang D. , Jove-Colon C. , Lichtner P. , Lorenz J. , Svec R. , Stubbs B. , Cooper S. , Bradley C. , Rutledge J. , Byrer C. 
Published: December 2007

Abstract
Sequestration of carbon dioxide (CO2) in depleted oil reservoir is a strategy currently being considered to reduce the amount of CO2 in the atmosphere. However, a better understanding and prediction of the geologic processes that control CO2 injection in porous geologic media is necessary before depleted oil fields can become a safe and economical sequestration option. This paper provides new experimental and modeling results from a Department of Energy's (DOE) National Energy Technology Laboratory (NETL) sponsored CO2 sequestration project investigating these issues. Geologic modeling and numerical flow simulations are used to study the feasibility of injection into porous media. Interactions between injected CO2, reservoir fluids and reservoir rock are taken into account, including CO2 dissolution in water and water reaction with reservoir rock. These results are helping to design geophysical monitoring studies to track the injected plume. Laboratory tests and reaction path simulations were also used to investigate the fate of injected CO2 with reservoir fluids and minerals during extended static tests with reservoir core and brines. Results may help identify long-term geochemical processes that will affect sequestration.
Monitoring WAG Pilot at VLE Field, Maracaibo Lake, by Perfluorocarbon and Fluorined Benzoic Acids Tracers
Authors: Hernandez C. , Alvarez C. , Saman A. , De Jongh A. , Audemard N. 
Published: December 2007

Abstract
It is widely accepted that comprehensive data acquisition programs are necessary for WAG management and pilot project interpretations. Common data acquisition methods used to monitore WAG processes are frequently analysis of separator testing, fluid composition, production/injection rates, pressures injection surveys, gas-oil ratios (GOR) and saturation logging. Chemical tracers have been used as a tool for monitoring water and gas injection, whereas for WAG process no experience in a field has been reported in Latinamerica. At the Lagocinco field, C2/VLE-305 reservoir (located in Maracaibo Lake basin) a WAG pilot project is currently being developed, using a chemical tracers program with Perfluorocarbon and fluorinated Benzoic acids. Five chemical tracers have been injected in both phases (water and gas) during WAG test as a surveillance tool for the process.
The aim to inject gas and water tracers was related to use breakthrough time and tracer production/injection history to get a better understanding of dynamic reservoir behavior and to support and upgrade the reservoir model.
This paper briefly describes the monitoring process achieved in Lagocinco pilot project, and some results of this monitoring in relation to the WAG process.
The result of the first water tracer test has indicated early breakthrough in four wells of the pilot project. One of the wells has increased oil production rate and three of them have maintained oil production rate and have decreased water cut and GOR as consequence of WAG process. The rest of the wells do not show a clear trend in tracer production, confirming heterogeneities in the pilot area. Zones not drained were identified and connection between the injector well and producer were characterized. The results of the first gas tracer have shown different distributions and velocities between gas and water. Finally, the second water tracer breakthrough was observed 3.3 months after its injection, just in one well, declaring that water distribution or path has changed as a consequence of WAG process.
Pressure Support Through Large Scale Gas Cap Water Injection At Prudhoe Bay
Authors: Jhaveri Bharat , Youngren Gary , Dozzo Joe , Schnell Lynn , Maguire Matt 
Published: December 2007

Abstract
The average reservoir pressure in the Prudhoe Bay field is declining at a rate of 25-35 psi/year. A large scale Gas Cap Water Injection (GCWI) project was recently sanctioned by the Prudhoe Bay Unit Owners to better maintain reservoir pressure and thus increase ultimate recovery. This paper presents key results from the reservoir analyses used in the design, evaluation and sanction of the project. Both mechanistic and full field compositional reservoir simulation studies were performed to develop a fundamental understanding of in situ recovery mechanisms and calculate project benefits. Reservoir uncertainty analyses included (1) assessment of early water breakthrough risks through reservoir description sensitivity studies, (2) evaluation of impacts on field gas and water injectivity and (3) quantifying impacts on gas recovery in the event of a major gas sales project. The paper also describes a field surveillance program that will be implemented to provide assurance that the project is performing as expected.
Next Generation Waterflood Surveillance: Behind Casing Resistivity Measurement Successfully Applied in the ‘A3-A6’ Waterflood at Elk Hills Field, Kern County, California
Authors: Starcher Mark , Mut Dave , Fontanarosa Mike , Davis Bob , Presmyk Chris 
Published: December 2007

Abstract
The project successfully used cased hole resistivity measurements to identify, isolate and access behind-flood-front oil in wells watered out as much as 10 years ago. The ‘A3-A6’ reservoir at Elk Hills has undergone peripheral waterflood for 20 years and has a Dykstra-Parsons permeability variation of ~ 0.7. Reserve development now targets bypassed oil.
In the past, determination of flood front position required open hole resistivity logs. Traditional cased-hole logs have been inconclusive as flood front monitoring tools. Only resistivity measurements provide the direct measurement to discern oil and water in this reservoir.
Watered out wells are mechanically prepped and then logged with a cased hole resistivity tool. Separation between the original and present resistivity curves indicates swept sands. When the open hole and cased hole resistivity curves overlay in sands, it gives a positive indication of unprocessed, bypassed oil reserves.
From this work, the ‘A3’ sand has been identified as unprocessed by the waterflood in several wells and processed in another well. Isolation and reperforation has resulted in commercial production in three wells to date. Behind casing resistivity measurement is the only logging method to successfully discern oil and water in the ‘A3-A6’ waterflood.
Every wet well is now reviewed as a candidate for this surveillance technology. Results demonstrate that behind-casing resistivity measurement is a next generation waterflood surveillance tool.
Quick Analysis of Steamflood, Bremer Fee, Midway Sunset Field, California, Using Production Enhancement Technologies (PET)
Authors: Heim Robin N. , Hampton Thomas J. , Laverty Bruce A. 
Published: December 2007

Abstract
This paper describes the application of a practical process to determine infill locations, reserves, and underperforming areas in cyclic and pattern areas in heavy oil fields.
Nuevo Energy Company had a need to quickly identify infill locations, reserves, and underperforming areas in Bremer Fee, Midway Sunset field, west of Bakersfield, California. The area used for the study consists of 393 wells over approximately 275 acres with just over 200 acres used in pattern and cyclic analysis. The challenge was to evaluate large data sets in a short time and a cost-effective manner.
The study incorporated techniques such as diagnostic plots, heterogeneity index, Voroni gridding, bubble maps, and pattern analysis from a well and reservir analysis software. The tools were used in a semi-automated process to quickly identify areas to improve steamflood performance by performing a geologic review, reserves analysis, production history review, cyclic well analysis, pattern analysis, and economic analysis.
From the study we determined oil-in-place and recovery, and looked at 393 wells in a low-cost, timely manner. We identified eight wells to be shut in, three wells to convert to injectors, several infill potential areas, and low-recovery areas. The infill areas independently validated Nuevo’s internal recommendations that had not been shown to Schlumberger staff performing the production enhancement technology (PET) analysis.
A Systematic Method to Estimate the Value of an Exploration Well
Authors: Dunn M. D. , Parnell L. A. 
Published: December 2007

Abstract
A systematic method designed to calculate the expected value of an exploration well is applied to an actual gas prospect in Cook Inlet, Alaska. This system of principles and procedures, herein referred to as the "Capen-Clapp" methodology, evaluates the significant factors that must be considered when a decision is made to drill an exploration well. These factors include geological risk, minimum economic reserve size, reserve size distribution, development costs, rate streams, commodity price, and discount rate.
The method is based on work published in Chapter 5 of The Business of Petroleum Exploration.1 The technique was developed over 20 years ago and has been used extensively for all types of exploration evaluations. Although this technique has been applied to hundreds of prospects, the application of this technique to an actual drill/no-drill decision has not been documented in the public domain due to the proprietary nature of most prospect evaluations. The source of the data is a published prospectus used to promote investment in the venture and therefore serves as a convenient case study to show how the technique is applied.
The discussion of the technique as applied in this case study shows that the Capen-Clapp methodology is thorough, easy to understand, and easy to apply to almost all types of exploration well evaluations. It accounts for all major factors that need to be considered when deciding whether to drill a prospect. It quantifies the risk in terms of one number, the expected value, which can then be used to rank the prospects of an exploration portfolio. This paper will benefit anyone faced with the challenging task of quantifying exploration risk and optimizing the value of exploration expenditures.
Petroleum Technology 2000
Authors: Birks J. 
Published: December 2007

1979 Hydrocarbon Economics and Evaluation, Dallas, February 11–13, 1979

Introduction
During the past 10 years, and particularly since the OPEC price increase since 1973, more and more attention has been directed to the price increase since 1973, more and more attention has been directed to the decreasing availability of oil and gas supplies in the world's total energy picture. Reports from the 10th World Energy Conference in Istanbul and IEA picture. Reports from the 10th World Energy Conference in Istanbul and IEA studies, have a fairly wide range of estimates for the amount of conventional oil which remains in the earth's crust, and the amount of it which is likely to be recoverable allowing for improvements in technology and substantial price increases. The most widely accepted interpretation of these data has led to the conclusion that the physical limits to world oil production may lie in the region of 80 million bpd. I need hardly remind you that these physical limits may exceed the actual amounts which OPEC countries, or any others with potential for net oil exports, may actually choose to produce and export. Out of these technical and political considerations, there has grown a consensus of opinion that oil availability is likely to reach a maximum in the late 1980s, thereafter leveling and even decreasing before the end of the century. As a recent IEA report states:
" Developments in oil producing countries during recent months have demonstrated how difficult it is to predict accurately when such a situation might arise. They have, moreover, shown clearly how exposed the world's oil supply system is, even in the short term, to unanticipated supply disruptions.
Nobody known exactly how much oil remains to be found or how fast it can be found and produced. What is certain, however, is that the world is using oil at the rate of nearly 20 billion barrels every year, and increasing. To maintain the status quo, we therefore need to find at least the equivalent of two Prudhoe Bays every year.
Achievements Of Energy Policy Goals Of Mexico
Authors: Chavarria-Garcia Jesus 
Published: December 2007

Introduction
MEXICO'S ENERGY POLICY IS STILL EVOLVING, BUT WE HAVE NOT HAD TO REVERSE OURSELVES ON ANY ELEMENT OF THE POLICY. WE ARE MOVING STEADILY TOWARD A COMPLETE AND SOPHISTICATED POLICY THAT ANTICIPATES MOST CHANGES AND INCORPORATES THE NECESSARY FLEXIBILITY TO ADJUST QUICKLY TO — WHATEVER CHANGES MIGHT BE NEEDED.
EACH COUNTRY'S ENERGY POLICY WILL NECESSARILY BE UNIQUE, SUBJECT TO — ITS OWN HISTORY, ITS ECONOMIC CHARACTERISTICS, ITS OWN TECHNOLOGICAL - SOPHISTICATION, AND KNOWN RESOURCE BASE FOR EACH FORM OF ENERGY. ALTHOUGH THE POLICY FOR EACH COUNTRY MIGHT BE UNIQUE, THERE ARE VARIOUS ELEMENTS OF POLICY THAT MAY CONTAIN ASPECTS COMMON TO SEVERAL COUNTRIES, AND SO PRECEDENT FROM OTHER COUNTRIES CAN BE USEFUL. THERE NOW EXISTS ABUNDANT PRECEDENT FROM OTHER COUNTRIES CAN BE USEFUL. THERE NOW EXISTS ABUNDANT EVIDENCE AS TO WHAT NOT TO DO.
WE WELCOME A SERIES OF TALKS WITH U.S. GOVERNMENT OFFICIALS THAT WILL COMMENCE SOON. WE WANT THESE TALKS TO BE SUCCESSFUL, AND ON OUR PART WE WILL TRY TO MAKE THEM SUCCESSFUL. WE VERY MUCH WANT TO SEE A STRONG AND ECONOMICALLY SUCCESSFUL UNITED STATES. IN FACT, WE ARE CERTAIN THAT A STRONG AND ECONOMICALLY SUCCESSFUL MEXICO WILL HELP THE UNITED STATES, NOT BE A DETRIMENT TO IT. THE POSSIBILITY OF MEXICAN NATURAL GAS EXPORTS WILL SURELY BE ON THE AGENDA OF THE MEETINGS; AND WE MAINTAIN AN OPEN MIND AND ARE WILLING TO LISTEN TO ALL REASONABLE PROPOSALS.
An Overview Of Project Financing For The Petroleum Industry (Domestic Cases)
Authors: Castle Grover R. 
Published: December 2007

Introduction
There are four main types of Project Financings that are common in the Petroleum Industry and these are:Type I - The Oil and Gas Production LoanType II - The Carved Out Production Payment FinancingType III - Project Financings Backed By A Guaranty of Completion, andType IV - Project Financings Backed By A Continuing Undertaking Such As A Throughput Agreement.
In this paper, I shall describe each of these four Types and present a separate Case for each type in order to illustrate the concept involved. The Cases used in this paper shall be confined to domestic financings, but the concepts described could also be adopted to international financings as well.

TYPE I
The Oil and Gas Production Loan is a loan to an independent operator or another type of loan to a company or individual that is based solely on the collateral of reserves of oil or gas in the ground. In Table A, I have constructed a projection that could be applicable to properties owned by an independent operator and in the next section of this paper, I have constructed a hypothetical Financial paper, I have constructed a hypothetical Financial Plan covering a loan to that operator. Plan covering a loan to that operator.

FINANCIAL PLAN FOR CASE I
March 31, 1979
Financing For An Independent Operator (An Oil And Gas Production Loan)
Proposed 4 1/2 Year Oil And Gas Proposed 4 1/2 Year Oil And Gas Production Loan To Production Loan To INDEPENDENT OPERATING COMPANY
Amount: $16,000,000 (to be taken down on June 30, 1979)
Purpose: To refinance existing debts and for Purpose: To refinance existing debts and for acquisition of additional leases.
Amortization: Effective with runs as of July 1, 1979,30% of Gross Income from the Property(Property) evaluated by Independent Petroleum Engineering Consultants as of July 1, 1979 (Report) shall be applied on a monthly basis against the Loan through December 31, 1979 and thereafter 50% of Gross Income shall be applied against the Loan. All amounts applied against the Loan shall go first to interest and then to principal.
In the event that the outstanding balance on the Loan on the dates indicated below shall exceed the Maximum Balance (Maximum Balance), then the Independent Operating Company(operator) shall make an Additional Payment (Additional Payment) in an amount sufficient to reduce the outstanding balance below the Maximum Balance.
(000's Omitted) Maximum Dates Balance
December 31, 1979 $15,500 March 31, 1980 14,500 June 30, 1980 13,500 September 30, 1980 12,750 December 31, 1980 11,750
Wet Gas Metering: Trends in Applications and Technical Developments
Authors: Mehdizadeh Parviz , Marrelli Jack , Ting Ven C. 
Published: December 2007

Abstract
Wet gas metering covers a variety of measurements in production streams with high to very high gas volume fractions. There is a need for direct measurement of gas under these conditions in such applications as gas condensate and high GOR fields as well as many production operations where gas from separation systems may contain liquid. More gas will be produced in the future from remote and subsea fields where production, capital investment, and operating costs must be optimized. For example, real time measurement of gas and liquid flow rate are critical in a subsea production system which will improve well allocation, optimize reservoir production, and enhance flow assurance. A number of wet gas metering strategies and systems have been developed to address these needs.
This paper reviews the principle of operations of commercially available systems, and evaluates their strength and limitations in various applications. Available data from test loops, pilot and field installations are used to assess the performance and accuracy of these wet gas systems. The field installations are used to identify the types of applications as well as the application trends that have utilized these systems. The paper also assesses the potential benefits from the deployment of a wet gas metering system.
The technologies employed in the current systems impose performance and accuracy as well as operational limitations. These limitations are outlined and evaluated in terms of operator expectations and requirements. The analysis is used to outline a list of issues that an operator has to consider in selecting and justifying a system for wet gas measurements in an asset development.
New developments that are ongoing or must be undertaken to address the limitations of the current wet gas metering systems are also reviewed. The implications of these developments to extend the future applications of wet gas metering systems are discussed.
Cubic Equations of State Applied to HT/HP and Highly Aromatic Fluids
Authors: Pedersen K. S. , Milter J. , Sørensen H. 
Published: December 2007

Abstract
PVT data are presented for 38 reservoir fluids counting fluids dominated by paraffins, heavy aromatic fluids with a significant content of C81+ and high-temperature-high-pressure (HT/HP) reservoir fluids. By properly taking into account the compositional differences, these fluid types can all be represented using a classical cubic equation of state (SRK or PR) with volume correction. The plus fraction is split into carbon number fractions and EOS model parameters assigned to each fraction. To keep the number of components at a manageable level the carbon number fractions are lumped into pseudocomponents, each containing several carbon number fractions. Hydrocarbons as heavy as C200 are considered when splitting up the plus fraction. Neglecting the content of components heavier than C80 will give a false picture of the phase behavior of heavy aromatic fluids. Correlations are presented for Tc, Pc and ω as a function of molecular weight and density. Problems are experienced representing the thermal expansion of stable oils using cubic equations of state in the classical form. It is shown that this deficiency can be cured by introduction of a temperature dependent volume correction term.
An Evaluation of the Application of Low Field NMR in the Characterization of Carbonate Reservoirs
Authors: Mai An , Kantzas Apostolos 
Published: December 2007

Abstract
Conventional reservoir analysis has always been an extensive process. In order to properly characterize a reservoir, cores and/or logs have to be obtained. Both core and log analysis is expensive and time consuming. NMR is an attractive alternative to these tools due to the fact that in theory, only one measurement is required. However, the conventional methods of interpreting NMR data only seem to work for simple sandstones. A new method of interpreting NMR data is required for complex porous structure such as carbonates.
It was found that NMR can predict porosity that is similar to the values obtained by gas expansion. By using the NMR data at fully saturated and irreducible water saturation (Swi), a T2cutoff value was obtained for each sample that separates the bound and movable fluid signals. It was found that T2cutoff for carbonates is not 100 ms as is widely believed by many people who have analyze NMR in carbonates. A correlation for T2cutoff was found as a function of the size of the last peak and its geometric mean. A correlation was also found for Swi, which was a function of the size of the first and last peak.
The Free Fluid and the mean T2 permeability models were evaluated. It was seen that the predictions from these models were not adequate. Another permeability model was developed, which is expressed in terms of the size of the first and last peak of the NMR spectrum obtained from the fully saturated sample. It was found that the correlation did a better job of predicting the permeability values. The new model has its own limitations, a method is currently being investigated to overcome these limitations. Despite these limitations, however, the new NMR permeability model provides better estimates of carbonate permeability than any other established methods.