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By Tony Lipiec, Greg Gosson

"When it comes to new mines being developed, there is a general industry consensus that most low-hanging fruit has been picked. Many projects currently in the mine development pipeline have been around for decades, but were held back because of technical challenges. Future development of these deposits will likely require access to the public capital markets, and in Canada that means providing scientific and technical disclosure on these deposits in compliance with NI 43-101. As many of these “challenged” projects have metallurgical issues, the companies that own the projects need to ensure their metallurgical Qualified Persons provide transparent disclosure regarding proposed solutions to those issues.This paper provides an overview of the disclosure requirements under NI 43-101 that are pertinent to metallurgists, and other Qualified Persons who prepare technical disclosure regarding the metallurgical characteristics of a mineral project. It lists the triggers for a technical report under NI 43-101 and Canadian stock exchange policies, and identifies the sections of the report that should involve input from a metallurgist or process engineer. It briefly outlines new civil liabilities under Canadian securities laws that increase the possible consequences for not complying with the technical disclosure standards.These materials are provided for general information purposes only and do not constitute legal advice. Readers are advised to seek specific legal advice from their own legal counsel in relation to any decision or course of action contemplated."

Jan 1, 2003

"The Companion Policy is guidance and not law. It sets out the views of the Canadian Securities Administrators (CSA) at to the manner in which the CSA interprets and applies certain provisions of NI 43-101 and Form 43101F1. The Companion Policy references the CIM Best Practice Guidelines for Mineral Exploration, and the Mineral Resources and Mineral Reserves, and that they should be followed by Qualified Persons.COMPANION POLICY 43-101CP TO NATIONAL INSTRUMENT 43-101 STANDARDS OF DISCLOSURE FOR MINERAL PROJECTS This companion policy sets out the views of the Canadian Securities Administrators (the “CSA”) as to the manner in which the CSA interprets and applies certain provisions of National Instrument 43-101 and Form 43-101F1 (the “Instrument”), and how the securities regulatory authorities or regulators (the “Securities Regulatory Authorities”) may exercise their discretion in respect of certain applications for exemption from provisions of the Instrument. PART 1 APPLICATION AND TERMINOLOGY 1.1 Supplements Other Requirements – The Instrument supplements other continuous disclosure requirements of securities legislation that apply to reporting issuers in all business sectors. 1.2 Evolving Industry Standards and Modifications to the Instrument- Mining industry practice and professional standards are evolving in Canada and internationally. The Securities Regulatory Authorities will monitor developments in these fields and will solicit and consider recommendations from their staff and external advisers as to whether modifications to the Instrument are appropriate. 1.3 Application of the Instrument -The definition of “disclosure” under the Instrument includes oral and written disclosure. The Instrument establishes standards for disclosure of scientific and technical information regarding mineral projects and requires that the disclosure be based on a technical report or other information prepared byor under the supervision of a qualified person. The Instrument does not apply to disclosure concerning petroleum, natural gas, bituminous sands or shales, groundwater, coal bed methane or other substances that do not fall within the meaning of the term “mineral project” in section 1.1 of the Instrument. 1.4 Mineral Resources and Mineral Reserves Definitions - The Instrument incorporates by reference the definitions and categories of mineral resources and mineral reserves as set out in the Canadian Institute of Mining, Metallurgy and Petroleum (the “CIM”) Definition Standards on Mineral Resources and Mineral Reserves (the “CIM Definition Standards”) adopted by the CIM Council on November 14, 2004, as amended. 1.5 Best Practices Guidelines for Mineral Resources and Mineral Reserves - A qualified person classifying a mineral deposit as a mineral resource or mineral reserve should follow the CIM Estimation of Mineral Resources and Mineral Reserves Best Practice Guidelines adopted by CIM on November 23, 2003, as amended. These guidelines are posted on www.cim.org."

Jan 1, 2003

"The technical report form provides the headings to be used and content required when a completing a technical report to be filed in accordance with NI 43-101. The technical report is meant to be a summary of the scientific and technical information on the mineral property. The Instrument (NI 43-101) requires that technical reports be filed with Canadian provincial or territorial securities regulators to support certain disclosure of mineral exploration, development and production activities and results in order to permit the public and analysts to have access to information that will assist them in making investment decisions and recommendations. FORM 43-101F1 TECHNICAL REPORT INSTRUCTIONS (1) The objective of the technical report is to provide a summary of scientific and technical information concerning mineral exploration, development and production activities on a mineral property that is material to an issuer.This Form sets out specific requirements for the preparation and contents of a technical report. (2) Terms used in this Form that are defined or interpreted in National Instrument 43-101 Standards of Disclosure for Mineral Projects (the “Instrument”) will bear that definition or interpretation. In addition, a general definitioninstrument has been adopted as National Instrument 14-101 Definitions that contains definitions of certain terms used in more than one national instrument. Readers of this Form should review both these national instruments for defined terms.(3) The qualified person preparing the technical report must use all of the headings of the items in this Formandmay create sub-headings. If unique or infrequently used technical terms are required, clear and concise explanations must be included. (4) No disclosure need be given in respect of inapplicable items and, unless otherwise required by this Form,negative answers to itemsmay be omitted. Disclosure included under one heading is not required to berepeated under another heading. (5) The technical report is not required to include the information required in Items 6 through 11 of this Form tothe extent that the required information has been previously filed in a technical report for the property being reported on, the previous technical report is referred to in the technical report and there has not been any material change in the information. (6) The technical report for development properties and production properties may summarize the information required in the items of this Form, except for Item 25, provided that the summary includes the materialinformation necessary to understand the project at its current stage of development or production. (7) The technical report may only contain disclaimers that are in accordancewith section 6.4 of the Instrument and Item 5 of this Form."

Jan 1, 2003

"NI 43-101 is a rule that governs how issuers disclose scientific and technical information about mineral projects to the public in Canada. The disclosure standards apply to oral statements as well as written documents and websites. NI 43-101 does not apply to disclosure concerning petroleum, natural gas, bituminous sands or shales, groundwater, or coal be methane. NI 43-101 first came into force on Feb. 1, 2001 and was revised in December 30, 2005. As a “National Instrument”, the law has been passed in each provincial and territorial legislature across Canada.“PART 1 DEFINITIONS AND INTERPRETATION 1.1 Definitions - In this Instrument “adjacent property” means a property(a) in which the issuer does not have an interest;(b) that has a boundary reasonablyproximate to the propertybeing reported on; and (c) that has geological characteristics similar to those of the property being reported on; “data verification” means the process of confirming that data has been generated withproper procedures, has been accurately transcribed from the original source and is suitable to be used; “development property” means a property that is being prepared for mineral production and for which economic viability has been demonstrated by a feasibility study; “disclosure” means any oralstatement orwritten disclosure made by oron behalf of an issuer and intended to be, orreasonablylikely to be, made available to the public in a jurisdiction of Canada, whether or not filed under securitieslegislation, but does not include written disclosure that is made available to the public only by reason of having been filed with a government or agencyof government pursuant to a requirement of lawother than securities legislation; “early stage exploration property” means a property that has(a) no current mineral resources or mineral reserves defined; and (b) no drilling or trenching proposed; in a technical report being filed in a local jurisdiction; “exploration information” means geological, geophysical, geochemical, sampling, drilling, trenching, analytical testing,assaying, mineralogical, metallurgical and other similar information concerning a particular property that is derived fromactivities undertaken to locate, investigate, define or delineate a mineral prospect or mineral deposit; “feasibility study” means a comprehensive studyof a mineral deposit in which all geological, engineering, legal,operating, economic, social, environmental and other relevant factors are considered in sufficient detail that it could reasonably serve as the basis for a final decision by a financial institution to finance the development of the deposit for mineral production; “historical estimate” means an estimate of mineral resources or mineral reserves prepared prior to February 1, 2001;“IMMM Reporting Code” means the classification system and definitions of mineral resources and mineral reservesapproved by The Institution of Materials, Minerals, and Mining in the United Kingdom, as amended; “JORC Code”means the Australasian Code for Reporting of Mineral Resources and Ore Reserves prepared by the Joint Ore Reserves Committee of the Australasian Institute of Mining and Metallurgy, Australian Institute ofGeoscientists and Mineral Council of Australia, as amended; “mineral project” means any exploration, development or production activity, including a royalty interest or similarinterest in these activities, in respect of diamonds, natural solid inorganic material, or natural solid fossilized organic material including base and precious metals, coal, and industrial minerals;"

Jan 1, 2003

The National Mining Hall of Fame and Museum (NMHF&M) will celebrate its 25th anniversary on Sept. 22, 2012 when the 2012 class is inducted during a special ceremony in Las Vegas, NV in conjunction with MINExpo 2012. The NMHF&M will induct four men representing the equipment manufacturing, minerals exploration, copper and coal sectors of the mining industry. The diverse cross-section of mining industry giants joining the hall of fame include Glen A. Barton, J. David Lowell, Samuel Newhouse and John Cleveland Osgood. They will join 214 other mining industry pioneers when they are formally inducted into the National Mining Hall of Fame at the 25th Silver Anniversary Induction Banquet & Ceremony. These men were selected for being visionaries, leaders and ambassadors within their own sectors and across the industry at large.

Jan 1, 2013

Ceremonies for the induction of four mining industry pioneers into the National Mining Hall of Fame will be held Saturday, Sept. 11, 2010 at the Charles F. Barber Pavilion of the Museum Convention Center in Leadville, CO. The 23rd Annual National Mining Hall of Fame and Museum Banquet will begin with an open house and reception at 5:30 p.m., followed by the dinner and program at 7 p.m. The four inductees are: William Wheeler Coleman who served 46 years, from 1911 to 1957, as president and chairman of the company that is now Bucyrus International of South Milwaukee, WI, a world leader in the manufacture of surface and underground mining equipment. Dr. Allen Van Heyl, Jr., an economic geologist who served with the U.S. Geological Survey for nearly 50 years beginning in 1943. He studied more of the nation?s mineral deposits than most could begin to imagine. Arthur Lakes contributed enormously to the geological and mining sciences in the western United States as a geologist, teacher, writer and artist over a period of more than four decades beginning in 1869. The Arthur Lakes Library at the Colorado School of Mines, Golden, CO, is named for him. Samuel Calvin McLanahan, through his inventive genius, changed the direction of his family?s company from that of a foundry to a leading manufacturer of minerals processing equipment to become today?s McLanahan

Jul 1, 2010

By NORA Mining Sector Council

The National Occupational Research Agenda (NORA) is a partnership program to stimulate innovative research and workplace interventions. In combination with other initiatives, the products of this program are expected to reduce the occurrence of injuries and illnesses at work. Unveiled in 1996, NORA has become a research framework for the National Institute for Occupational Safety and Health (NIOSH) and the United States. Diverse parties collaborate to identify the most critical issues in workplace safety and health and develop research objectives for addressing those issues. NORA entered its third decade in 2016 with an enhanced structure. The 10 sectors formed for the second decade will continue to prioritize occupational safety and health research by major areas of the U.S. economy. In addition, NORA’s seven cross-sectors will continue to focus on the major health and safety issues affecting the U.S. working population. While NIOSH serves as the steward to move this effort forward, it is truly a national effort. NORA is carried out through councils comprised of members with many diverse interests that are developing and implementing research agendas for the occupational safety and health community over the third decade (2016-2026) of NORA. Councils address objectives through information exchange, partnership building, and enhanced dissemination and implementation of evidenced-based solutions. NORA groups industries into 10 sectors using North American Industry Classification System (NAICS) codes. The Mining Sector encompasses NAICS code grouping 21xxxx where “xxxx” represents the different subcodes of the mining “21” classification. Mining encompasses the extraction of solid mineral and mineral-like substances from their place in the Earth’s crust and supplies them to processing industries that produce economically valuable materials. It does not include oil and gas extraction. The Mine Safety and Health Administration, MSHA separates mining into coal, underground and surface, and metal and nonmetal, underground and surface.

Feb 1, 2024

By William Bergeson

"BACKGROUND As of December 2015, there are roughly 475 road tunnels within the United States according to the most recent national tunnel inventory data compiled by the Federal Highway Administration (FHWA); whereas, there are more than 615,000 highway bridges on public roads. The FHWA estimates that tunnels represent nearly 100 miles of Interstates, State routes, and local routes. Tunnels are part of the national transportation infrastructure and represent a significant financial investment for the owner and, hence, the tax payers. Tunnels, that are not properly maintained, usually require more extensive repairs and consume more resources. Tunnels must provide safe, reliable, and effective transportation even as these structures age and deteriorate. Furthermore, tunnels generally remain in service for extended periods of time due to their very high construction costs. For example, many tunnels were constructed decades ago during two historic periods of highway system expansion; the first period correlated with the era of public works programs linked to the Great Depression of the 1930-40s; and the second period of expansion occurred with the building of the interstate highway system in the 1950-60s. As such, these tunnels are fast approaching 60 to 80 years old. Congress enacted the Moving Ahead for Progress in the 21st Century Act (MAP-21), which was signed by the President on July 6, 2012. This legislation followed a fatal tunnel incident on July 10, 2006 and a National Transportation Safety Board (NTSB) report1 that noted the importance of conducting regular tunnel inspections. MAP-21 authorized the Federal Highway Administration (FHWA) to develop a mandatory inspection program for all tunnels on all public roadways (Bergeson and Ernst 2015): To help safeguard tunnel users and to ensure reliable levels of service, the FHWA developed the National Tunnel Inspection Program (NTIP), which is comprised of the National Tunnel Inspection Standards (NTIS), the Tunnel Operations Maintenance Inspection and Evaluation (TOMIE) Manual, the Specifications for National Tunnel Inventory (SNTI), and the Manual for Bridge Evaluation (MBE). The data collected from the program will be stored in a National Tunnel Inventory (NTI) database. A comprehensive and refresher training program was also developed to help qualify and certify key tunnel inspection personnel to include the program manager and team leader."

Jan 1, 2016

By Roman Z. Pyrih

Subsurface migration of cyanide is attenuated by naturally occurring geochemical and biogeochemical processes. Geochemical mechanisms which remove or immobilize cyanide and metal-cyanide complexes include precipitation/coprecipitation, sorption, and volatilization. Geochemical properties of soils and geochemical materials that promote the functioning of these mechanisms include the following: 1) acidic soil pH; 2) presence of illite and smectite clays; and 3) presence of iron hydrous-oxides and organic carbon. Naturally occurring soil microorganisms play perhaps a more important role in attenuating cyanide movement than previously realized. Biodegradation of cyanide is a "renewable" process, limited in its effectiveness by the avalibility of oxygen and micronutrlents (usually phosphate) to the microorganisms.

Jan 1, 1990

By Anderson Meireles, Leonardo Soares Chaves, Raul Carretero Hoz, Carlos Eduardo Soares Feliciano, Renato Jacome Costa

The large iron deposits in the northern region of Brazil located in the Amazon Craton have in common the presence of natural cavities. These cavities primarily occur in the upper layer of the ore body, formed above hematite mineralization. Their origin remains a topic of debate, often associated with hydrothermal drainage processes and erosive evolution. Over time, these cavities have become integral to the local environment, each contributing to the regional ecosystem of fauna, flora, and the significance of speleothems found within them. Managing these cavities poses a significant challenge for iron mines in the area. On one hand, they must preserve the cavities from anthropogenic actions, while simultaneously handling heavy equipment and large volumes. In 2023, the development of the mine took place towards the cavity under study, revealing systematic deviations in vibrations recorded during nearby detonations as the blasting got nearer. To address this, a work plan was put in place, emphasizing a straightforward approach: constructing lithology-specific vibration models, defining charge abacuses, and optimizing timing to reduce charge amplification. Implementing this methodology significantly improved adherence to the vibration limit, resulting in an around 50% reduction in standard error. This paper presents the consolidated work that allowed mining activities to continue in the area through controlled blasting, effectively mitigating potential anthropogenic damage in sensitive areas.

Jan 21, 2025

By V. Panayotov, M. Panayotova

"Wastewater from ores processing is often polluted by molybdate and sulfate (SO42-) ions. Sorption is one of suitable methods for removing those pollutants when presenting in low concentrations. This work reports results on adsorption of sulfate and molybdate ions on metal modified (with barium - Ba and lead - Pb) and organic reagent modified (with Hexadecyl-trimethyl-ammonium bromide - HDTMA) clinoptilolite. Zeolite’s modification with Pb, Ba and HDTMA increases its uptake capacity with respect to Mo(VI) at pH 3, with the uptake capacity decreasing in the order CL-Pb > CL-HDTMA > CL-Ba. Lead-modified clinoptilolite shows high uptake with respect to Mo(VI) in acidic, neutral and slightly alkaline conditions. The presence of SO42- in concentrations twice higher than the amount of Mo(VI) do not interfere with the Mo(VI) removal by CL-Pb. Zeolite’s modification with Ba and Pb renders it able to immobilize SO42- from water in the pH range 3-9. Kinetics of the uptake process is best described by the pseudo-first order kinetic equation. Increasing the initial concentrations of Mo(VI) and SO42- increases the removed amount of pollutants. INTRODUCTION Wastewater from copper-molybdenum ores processing is often polluted by molybdate and sulfate ions. Molybdenum (Mo) migrates easily in water and consequently the Mo polluted areas could extend for hundreds and thousands of meters (Ryzhenko, 2010). Molybdate anion is the only Mo(VI) species in natural water, i.e. at pH > 6.0. Its median freshwater hazardous concentration affecting 5% of the species (HC 5.50%) is 38.2 mg Mo/L (De-Schamphelaere et al., 2010). The marine water chronic toxicity (HC 5.50%) is assessed at 5.74 mg Mo/L (Heijerick et al., 2012). The predicted no-effect concentrations (PNEC) are 12.7 mg Mo/L and 1.92 mg Mo/L correspondingly for freshwater and marine water (Heijerick et al., 2012a). When sulfates present in drinking water in excess of 250 mg/L they cause a cathartic action (especially in children) in the presence of sodium and magnesium, and when the concentration exceeds 600 mg/L, diarrhea. When sulfate-rich effluents are discharged into the environment, they may increase the acidity of water bodies and soils (Guimarães and Leão, 2014). Because of the adverse effects to human health and the environment, limits are set for SO42- concentrations in waters and wastewaters in the range of 250 / 500 mg/L."

Jan 1, 2018

By Edmund C. Bovey

"AS I begin my remarks this morning, please let me say how honoured and gratified I was to receive your invitation to address you here during your deliberations in historic Quebec City. The high esteem in which your Institute is held is reflected in the respect and deference accorded to it by industry across Canada. I feel privileged to be here with you today.I would like to discuss with you some applications of natural gas in the mining industry and suggest to you, in closing, some possible avenues of future development.Natural gas first became avail-able for industrial purposes in Northern Ontario in late 1958. Acceptance of natural gas, as a source of energy by the industry of that area, has been both widespread and gratifying. The mining industry of Northern Ontario has in-creased its annual use of natural gas by approximately 35 per cent each year since 1958. We believe that this trend will continue, al-though we will probably have to accept a more modest 10 per cent annual gain as the market approaches saturation. I would like to explain how we were able to do this and where all this gas is used. Our first sales were largely a matter of price-and the savings we offered were substantial."

Jan 1, 1966

By R. T. Elworthy

Canada ranks second in the list of world consumers of natural gas. In 1923 our production was nearly fifteen million thousand cubic feet valued at $5,800,000. Our output, however, appears very small compared with that of the United States, which in 1923 totalled over one thousand and eight million cubic feet, valued at $240,000,000. Natural gas is found in commercial quantities in three? provinces in Canada. New Brunswick: Natural gas in New Brunswick has been utilized commercially only since 1912,although the investigation of oil and gas possibilities of the province commenced as early as 1859. The annual production is a little more than one-twentieth of the total Canadian production and remains fairly constant from year to year. Ontario: In Ontario the earliest gas wells were drilled in Essex and Welland counties between the years 1885 and 1890. On account of the small demand in Canada the cities of Detroit and Buffalo were supplied with large quantities of gas from these wells, but this export was curtailed in 1898 and finally ceased in 1900. The production of natural gas in Ontario, mainly from fields in Lambton, Kent, Essex, Norfolk, Haldimand and Welland counties, increased rapidly from 1900 until the peak was reached in 1917, when over nineteen million thousand cubic feet valued at $3,641,587 was consumed.

Jan 1, 1925

By Frank Marotta, Louis B. Lesem, Frank Greytok, John J. McKetta

Although one of the primary variables in the calculation of the flowing bottom-hole pressure in gas wells from surface measurements is the temperature at any point and its distribution in the flow-string, only few experimental data are available in the literature and little attention has been given to analysis of the problem. Virtually all of the recently published methods of calculating flowing bottom-hole pressures depend on the assumption that either the temperature is constant at some average value or that the variation is linear with depth. The purposes of this work are to analyze the problem theoretically and to verify the analysis by comparison with experimental data so that practical problems in the analysis of the behavior of gas wells can be solved with greater accuracy, reliability, and ease. MATHEMATICAL OUTLINE OF PROBLEM Assuming that: 1. The mass velocity and chemical composition of the gas stream are constant and in normal gas well operations, the change in linear velocity in the entire flow-string is trivial, 2. The product of the density and heat capacity of the gas is constant, 3. No horizontal temperature gradient exists in the gas stream, 4. Net flow of heat by conduction within the formation and in the gas stream in the vertical direction is trivial in magnitude and can be neglected, 5. The regional vertical geothermal gradient is constant, and 6. The temperature of the gas entering the borehole is constant, and equal to that of the reservoir, a set of two simultaneous, linear partial differential equations with appropriate boundary conditions was derived to describe the temperature distribution in the gas stream and the surrounding formation. These equations were solved by operational techniques for the distribution of temperature in the gas stream. The resulting integrals were evaluated numerically on an IBM 604 at the Machine Accounting Div. of the Railroad Commission of Texas. DERIVATION OF FUNCTIONS FOR THE DISTRIBUTION OF TEMPERATURE The physical system is a circular hole of radius a in an infinite medium with thermal conductivity K, density p8, and heat capacity c,. Under shut-in conditions the well is in thermal equilibrium with the surroundings and the increment in temperature is given by - ?T3/L x. Gas of density pg and heat capacity c.. flows upwardly through this hole in the direction of increasing x with a linear velocity W. Writing a heat balance on an element of gas ?x in thickness, convective heat transfer + conductive heat transfer + energy required to lift a unit mass of fluid = change in energy content. pa2W po Co To - pa2Wpo Co To x+xx - 2apK?x ?T8/?r r=a - Wpa2 po?x/778 = CoPopa2?x?To/?t... Dividing by (copopa2?x) and taking the limit as ?x tends to zero, -W (?To/?x + 1/778Co) + 2 K/a Po Co ?T3/?r r=u = ?To/?t

Jan 1, 1958

By J. M. Campbell, T. S. Buxton

The most widely used methods of predicting the volumetric properties of gas are based on the principle of corresponding states, which asserts that the compressibility factor is a universal function of reduced temperature and pressure. Previous studies have shown that the acentric factor, as proposed by Pitzer, l is an important addition to reduced pressure and reduced temperature as factors affecting the compressibility factor. Results of this study indicate that, if the pseudocritical temperature and pressure used to determine the reduced conditions are adequately predicted, characterization of natural gas-carbon dioxide mixtures with the acentric factor will allow reliable determination of the compressibility factor. Comparisons of predicted and experimental compressibility factors have shown that the pseudo-critical constant rules of Stewart, Burkhardt and Voo 2 are satisfactory for hydrocarbon mixtures. However, these rules fail to predict the pseduo-critical constants for hydrocarbon-carbon dioxide mixtures. Based on graphically determined pseudocritical temperatures for binary hydrocarbon-carbon dioxide mixtures, a correlation which gives the required correction to the Stewart, Burkhardt and Voo rules was prepared and a compressibility factor prediction technique was proposed. To test the proposed technique, compressibility factors for live mixtures of methane, carbon dioxide and either ethne or propane were experimentally determined at 100, 130 and 160F and pressures up to 7,026 psia. The predicted and experimental compressibility factors for these live mixtures had an average absolute deviation of 0.55 percent. INTRODUCTION Two-parameter generalized correlations based on the principle of corresponding states (PCS) are presently available for reliably predicting the compressibility factor of lean natural gas, i.e., natural gas with low concentrations of hydrocarbons heavier than methane. When these same correlations are used for mixtures of natural gas and carbon dioxide, large deviations between actual and predicted compressibility factors are observed. This study was undertaken to provide a means for accurately predicting the compressibility factor for such mixtures. In the past, two avenues of approach have been employed to extend the applicability of the PCS. The first has been to introduce additional parameters. The second has been to develop combination rules for predicting pseudocritical constants which do not suffer from the limitations of the commonly used molal average constants. In this study, both of these approaches have been considered and employed to arrive at a method for predicting the compressibility factor of mixtures of hydrocarbons and carbon dioxide. SELECTION OF A THIRD PARAMETER Failure of the original PCS to predict the compressibility factor for all pure gases, regardless of their mass, shape or polar moment, has led to the introduction of additional parameters into the PCS. Parameters have been introduced to correct for quantum deviations,3-5 non-spherical or globular shapes6-9 and for polar moments.8-12 In addition to these parameters which are based on some microscopic property and intended to correct for some specific cause of deviation, more general parameters based on some bulk property have also been introduced.1913-16 To use additional parameters to correct for each of the possible causes of deviation among the individual constituents of a gas mixture would require a rather complex form of the PCS. To maintain the PCS in as simple a form as possible, it is more desirable to have a single third parameter which is based on some bulk property influenced by several of the factors causing deviations. The third parameter selected for use in this study is a factor originally proposed by Pitzer.9

By M. R. Tek, F. H. Poettmann, M. L. Grove

The general problem of single-phase natural gas flow through porous media has been considered both by mathematical analysis and field experiments. Theoretical studies on the fluid dynamics of natural gas wells resulted in derivations of expressions which permit a ber-ter understanding of the flow mechanism for conditions under which Darcy's law is no longer valid. In applying these results to natural gas production and testing technology, special emphasis war placed on the study of low permeability, slowly stabilizing formations. These applications resulted in a method of predicting the performance coefficients of tight natural gas wells. The calculation of the performance coefficient requires the determination of the "test-index", pkh/µ, the drain- age radius, R, and the effective wellbore radius, rw. Methods for estimating these parameters from field data were also developed. Field data from 15 wells were collected and analyzed. The measured values of the performance coefficients were compared with the predicted values. This statistical evaluation gave a bias of 7.14 per cent and a standard deviation of 11.6 per cent. INTRODUCTION The performance of a natural gas well is determined by the physical properties of the reservoir rock, the extent and the geometry of the drainage area, the properties of the flowing fluid, and the conditions of pressure distribution within the drainage matrix. The relation between the quantity of gas delivered and the pressure drop within the reservoir is characteristic of the behavior of each well and is often referred to as the back-pressure behavior of the well. It is well established that for normal, single-phase gas wells the relationship between the gas delivery rates and the bottom-hole pressure take, in general, the form, Q = c(P3 8 -P2 1)n. ,.......(1) where C is the performance coefficient, and n is the exponent corresponding to the slope of the straight-line relationship between Q and (P2 s, — P2 l) plotted on logarithmic coordinates. The determination of a well's performance by the back-pressure behavior not only permits the production engineers to analyze many operating problems, but also provides necessary information useful and essential to predict the future development of the field.' Important engineering and production problems such as calculation of gas deliverability into a pipeline at a predetermined line pressure, design and analysis of gas-gathering lines, determinations of spacing and number of wells to be drilled during field development to meet future market or contract obligations, etc., all depend, at least in part, on the availability and use of reliable back-pressure curves.' In the past the behavior of gas wells was evaluated

Jan 1, 1958

By H. O. McLeod, J. M. Campbell

This paper presents the results of the data obtained in the first stage of a long-range study at high pressures of the system, vapor-hydrate-water rich liquid-hydrocarbon rich liquid. The data presented are for the three-phase systems in which no hydrocarbon liquid exists. Tests were performed on 10 gases at pressures from 1,000 to 10,000 psia. One of these was substantially pure methane, and the remainder were binary mixtures of methane with ethane, propane, iso-butane and normal butane. Several conclusions may be drawn from the data. 1. Contrary to previous extrapolations, the hydrocarbon mixtures tested form straight lines in the range of 6,000 to 10,000 psia which are parallel to the curves for pure methane, when the log of pressure is plotted vs hydrate formation temperature. 2. The hydrate formation temperature may be predicted accurately at pressures from 6,000 to 10,000 psia by using a modified form of the Clapeyron equation. The total hydrate curve may be predicted by using the vapor-solid equilibrium constants of Carson and Katz' to 4,000 psia and joining the two segments with a smooth continuous curve between 4,000 and 6,000 psia. 3. The use of gas specific gravity as a parameter in hydrate correlations is unsatisfactory at elevated pressures. 4. The hydrate crystal lattice is pressure sensitive at elevated pressures. INTRODUCTION Prior to 1950 many studies had been made of the hydrate forming conditions for typical natural gases to pressures of 4,000 psia.""'"'"" Most of these attempted to correlate the log of system pressure vs hydrate formation temperature, with gas specific gravity as a parameter. One of the more promising correlations was made by Katz, et al, which utilized vapor-solid equilibrium constants. The only published data above 4,000 psia are those of Kobayashi and Katz7 for pure methane to a pressure of 11,240 psia. In the intervening years, most published charts for the high-pressure range have represented nothing more than extrapolations of the low-pressure data, with the methane line serving as a general guide. The reliability of these charts has become increasingly doubtful (and critical) in our present technology as we handle more high-pressure systems. The portion of our high-pressure hydrate research program reported here was designed to: (1) investigate the reliability of existing charts; (2) obtain actual data on gas mixtures to 10,000 psia; and (3.) develop a simple hydrate correlation that was more reliable than those which simply used specific gravity as a parameter. Binary mixtures of methane and ethane, propane normal butane, or iso-butane were injected into a high-pressure visual cell containing an excess of distilled water. Hydrates were formed and then melted to observe the decomposition temperature of the hydrates at pressures from 1,000 to 10,000 psia. EQUIPMENT The equipment consisted of a Jerguson 10,000-lb high-pressure visual cell, a 10,000-1b high-pressure blind cell and a Ruska 25,000-1b pressure mercury pump. The visual cell was placed in a constant-temperature water bath controlled by a refrigeration unit and an electric filament heater. A Beckman GC-2 gas chromatograph was used in analyzing the gas mixtures after each run was completed. EXPERIMENTAL PROCEDURE After evacuating the gas system, the heavier hydrocarbon was injected into the high-pressure mixing cell to that pressure necessary to give the desired composition. This cell then was pressured to 1,100 to 1,200 psia by methane from a high-pressure cylinder. The mixing cell holding the gas contained a steel flapper plate and was shaken intermittently over a period of 15 minutes. After mixing, the valve to the high-pressure visual cell containing excess distilled water was opened, and the gas mixture was allowed to flow into the cell. The temperature in the water bath was lowered 10" to 15'F below the estimated hydrate decomposition point. As a first check, the temperature was increased at a rate of 1°F every six minutes to find the approximate point of decomposition. It was again lowered 1.5° to 5°F to form hydrates. The temperature was raised to within l° of the estimated decomposition point and then increased 0.2F every 10 to 15 minutes until the hydrates decomposed. This procedure was repeated at various pressures to obtain 7 to 13 points for each mixture between 1,000 and 10,000 psia. After completion of the hydrate decomposition tests, the gas mixture composition was analyzed with a calibrated gas chromatograph. These gas analyses have an estimated error of ± .1 per cent.

By A. Satter, J. M. Campbell

Reported herein are the results of a careful and detailed study of the non-ideal behavior of pure gases and their mixtures. Included are: (1) new data on five ternary systems composed of methane, ethane and H2 S; (2) a simple compressibility factor correlation that is inherently superior to present correlations, particularly for gases containing H2S and CO2; and(3) a detailed study of combination rules and the effect of system composition on the choice thereof. This study makes use of the rather large mass of data already available in the literature. A complete re-examination of the data and ideas presented in the last 25 years was considered desirable as a prelude to our basic concern — the effect of diluents on gas behavior. A consideration of both the macroscopic and microscopic properties of gases provides a better insight which, in turn, gives a firmer basis for improved correlation techniques. Such a study has shown that expressing the compressibility factor Z as a function of acentric factor w, as well as reduced temperature and pressure, yields a correlation that is broader in scope. The study of various combination rules has shown that better results are obtained by "tailoring" the rule used to the system composition. To do so improves the basic reality of results by overcoming some of the anomalies often found when using Kay's rule alone. Tentative recommendations are made regarding the most reliable combination rule for use with a given class of gas. The data presented are useful for estimating the direction and magnitude of the expected deviation when using a given rule. Although more work is needed, particularly around the critical region and with CO2 mixtures, the advantage of the classification scheme proposed is apparent. INTRODUCTION When one attempts to write a PVT equation to fit the data for actual gases, greater precision is obtained by the use of a multiple number of empirical constants. This has lead to multiple-constant equations such as Benedict-Webb-Rubin, Beattie-Bridgman, Keyes, etc., which are capable of yielding very precise results for pure gases in a range for which data to get the constants are available. As a matter of practicality, though, the use of such equations for gas mixtures is limited. Because of the infinite number of gas analyses available, any attempt to compile the constants needed requires a prohibitive amount of experimental data. This could be overcome by the use of a combination rule, but there is no real advantage in doing so because the end result offers no practical impovement over the Z factor correlation. The most widely used method of predicting the volumetric properties of pure gases is based upon the "theorem of corresponding states". According to this theorem, "all pure substances have corresponding molal volume at corresponding temperature and pressure if the reference point of correspondence is the critical point". Generalized compressibility charts for gases were prepared first by Cope and associates1 in 1931 and later by Brown and co-workers2 in 1932. However, the most commonly used charts are those of Dodge,3 Nelson and Obert,4 Hougen and atsson: and Standing and Katz.6 The work of Katz and co-workers has provided us with basic data for the hydrocarbons most widely used today. Their original chart6 was compared with a relatively large amount of multi-component data for gases consisting almost entirely of normal paraffin hydrocarbons. A deviation of only + 1.2 per cent was obtained.39 In the 20 years following publication of this work it has been found that the behavior of most mixtures of paraffin hydrocarbons could be predicted by this correlation within at least 5 per cent. Where difficulty has been encountered it has largely involved one or more of the following circumstances: pressures above 4,000 psig, mixtures containing large amounts of heavy ends and/or aromatics, systems in the critical region and mixtures containing polar compounds and/or CO2. The abnormal error sometimes found with such gases, not too unexpected for this method, is

By A. B. Cook, C. J. Walker, G. B. Spencer

Although water will displace oil from a petroleum reservoir to a greater extent than gas will, there are some reservoirs in which gas rather than water should be used for pressure maintenance. This is indicated by the high-percentage oil recovery in the case history reports on the Pickton field1 in East Texas and the Raleigh field2 in Mississippi. In gas cycling, total oil recovery includes vaporized products from the immobile oil in addition to oil produced by displacement. If a large part of the immobile oil is vaporized, total oil recovery may be higher than that obtainable from pressure maintenance by water injection. However, the amount of immobile oil vaporized may range from almost 0 to 100 percent, and no simple and reliable method has been presented in the literature for calculating oil vaporization. Development of such a method was the purpose of this study. Several papers concerning the calculation of oil vaporization have been published,3 6 and each is based on the concept dealing with K values — equilibrium constants for the various components in reservoir oils. (K for a component in a system of vapor and liquid in equilibrium is the mole fraction in the vapor phase divided by the mole fraction in the liquid phase.) This appears to be the most logical approach. Yet, the problem is too great for a perfect solution, even with modem laboratories to analyze oils and high-speed digital computers to perform calculations; the number of components in reservoir oils is too large. Because of their complexity no two reservoir oils are exactly alike. Also, K values change not only with variations in pressure and temperature but also with composition of the reservoir oil. In addition, during gas cycling, the lighter hydrocarbons tend to vaporize first. Thus, the reservoir oil becomes more dense and less volatile as gas cycling continues. Furthermore, the greatest amount of oil vaporization occurs near the injection well. Therefore, a simplified method is required for calculating oil vaporization because a rigorous method is not practical. The present methods of calculating vaporization generally require knowledge of the reservoir oil composition in which the mole fractions of the lighter components through hexanes are given; the remaining oil is described as C, + (heptanes and others of greater molecular weights). Assigning one K value for the C,+ system provides the simplest solution, but this incorrectly assumes that K for C, + does not change as gas cycling continues. This assumption can cause large errors because the K value may become less than a thousandth of the original after a large amount of oil vaporization. Another way to solve the problem is to determine changing K values for C, + according to how much of the C, + has been vaporized. To determine these values a sample of the reservoir oil is injected into a pressure-volume cell, and dry gas is batched in and out of the cell. Appropriate measurements and tests are made to determine K

Jan 1, 1970

By C. E. Turner, J. R. Elenbaas, R. D. Grimm, J. A. Vary, D. L. Katz

A technique is presented by which well samples and core plugs of dolomite formations are classified by microscopic examination into seven different porosity grades. Quantitative values of porosity and permeability are determined for each grade by a statistical correlation of the core plug test data with the porosity grading system. These quantitative values are applied directly to the grades exhibited in the well samples for the purpose of estimating the reservoir void space for wells that were not cored. The procedure is described for estimating the gas reserves per unit area lor the South Hugoton gas field. but a reserve estimate for the field is not given. INTRODUCTION The miscroscopic examination of well sample; and the graphic recording of their lithologic qualities and other distinguishing characteristics of various geologic formations drilled is both a science and an art of long standing and wide application. Usually the primary objective of a geologist who "sits on the well" and examines the samples are: to identify the formation being drilled, determine the total depth, casing point. and completion interval. In most cases the porosity is described. if done at all, in general terms. such as: trace, scattered, fine, poor, fair, medium. good, excellent, or in some other relative terms. In fields where various geologists have examined samples and recorded observations on many wells considerable variations in lithologic terms and porosity descriptions occur unless there is primary effort to establish uniformity of logging observations and standards of recording observable porosity. When an estimate of the pore volume of a reservoir is made a geologic concept of the processes that control the magnitudes of porosity and permeability is developed by microscopic examination of well samples. The characeristics and appearances are then mentally related to rather general quantitative units of porosity based on physical core data from the same reservoir or on such data or experience in other reservoirs that have similar qualities. The reliability of such estimates depends largely on the variations of the lithology of the formations, the geometric properties of its void system. the extent of comparisons of sample appearances with porosity data, as well as the uniform recording of all relevant characteristics. This statement is particularly significant for dolo-mitized limestone formations of substantial thicknesses and heterogeneity such as the Permian Dolomites of the Hugoton gas field. Jn this field, as well as in most of the Permian Dolomite fields, the producing formations are of relatively great thicknesses in which the porosity and permeability of the reservoir varies substantially in all directions, depending on the crystalline structure. degree and kind of impurities, kind of fossils anti cementation thereof, degree of dissolution. and fracturing. The variations of the lithologic texture of the dolomites and post deposition alterations have resulted in porosities and permeabilities of such magnitudes that only a part of the gross thickness can be counted as "pay." At the time of this study insufficient gas production had been experienced to apply the pressure decline production method in the South Hugoton Field and the electric logs are not definitive enough. The problem of estimating gas reserves in the south part of the Hugoton Field is primarily one of determining the pay thickness and porosity from well samples and core data. The area studied embraced all that part of the field lying south of an east-west line through Guvmon, Okla., anti containing approximately 1.000,000 acres. This paper describes a technique of correlation of physical core data with well samples so that quantitative values of pay thickness, porosity. Permeability, and connate water may be assigned to well samples that are representative of a given interval, and thereby permitting the estimation of gas reserves lor a given unit area. The procedure was developed by a uniform microscopic qualitative porosity grading of the dolo. mite core plugs.. and relating these grades to the respective physical core data on a statistical basis The well sample-were also graded in a Similar manner in order that the quantitative values established lor the core plugs could be applied to the well Sample for wells that were not cored. GRADING OF DOLOMITE A group of experienced geologists was given the assignment of examining the samples on all wells in South Hugoton in order that they could log their observations in a uniform and standardized manner and grade the observed porosity so that it could be related quantitatively to the core data. The group initiated the study 011 chips from cores which bad been tested for porosity and permeability. This study continued until all of the geologists developed a common knowledge of lithologic terms and of the characteristic appearances of the samples and their relations to measured porosity. The characteristic appearances of the dolomite samples under twelve-power magnification as related to their qualitative porosities afforded a classification of the dolomite into :even grades of porosity, ranging from dolomite of no-visible porosity under twelve-power magnification to dolomite of excellent porosity. The assigned grade for a specific 10-ft interval is a weighted average of all visible grades of porosity exhibited by the cuttings representing that interval. The porosity characteristics were recorded by a color graph adjacent to the lithology column in conjunction with a numerical system for further definition of relative porosity as shown in Fig. 1. The three vertical lines to the right of the lithology column each represent 33 1/3 per cent. which lines were used to record the percentage of the samples, for any particular interval. that showed porosity under the microscope. The colors were used to denote actual pore size. i.e., orange. blue and I-ed for pore diameter of one-fourth or less. one-fourth to one-Ilalf. and greater than one-half millimeter, respectively. The area colored 1)). one or more colors represents the percentages of the samples exhibiting pores of the respective size or sizes. The numerals from one to six inclusive shown on the log in

Jan 1, 1952