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By Z. F. Dai

The Thompson Nickel Belt, located in Northern Manitoba, Canada, contains more than 400 million tonnes of ultramafic low-grade nickel mineralization in 9 deposits. One of these, the Pipe deposit, was mined between 1971 and 1983 producing a Ni concentrate of 9% to 11% grade at 73% recovery. The operation was terminated because the poor recovery, low Ni grade and high MgO con-tent of the concentrate made processing this ore uneconomical at the metal prices prevailing at that time. Vale Inco is now re-evaluating these deposits with the intent of providing a new source of concentrate for its Thompson integrated processing facility. It is known that serpentine slimes coating on the sulphide surfaces are responsible for the poor metallurgy. Various desliming methods were tested including settling, elutriating, tabling and hydrocycloning. Hydrocycloning has proven to be the most effective means of desliming. With a feed assaying 0.70% Ni and 33% MgO, a rougher flotation concentrate assaying 22.7% Ni and 4.8% MgO was produced at a Ni recovery of 62.5% (relative to the feed to grinding), with no utilization of slimes dispersants. Another 16.6% Ni recovery was achieved in scavenger flotation resulting in a total Ni recovery of 79.1%. Batch flotation tests using various flowsheet configurations to optimize the grinding, desliming, reagentizing and flotation conditions are in progress.

Jan 1, 2014

By J. S. Becker

Technology developed and first implemented in the United Kingdom enables very low grade aluminum scraps containing oils, organics, plastics and ferrous metals to be directly charged, without pretreatment, into a unique melting furnace. The system has been in full scale production for over three years. The oxy-fuel-based furnace design incorporates internal afterburning in the furnace's hot zone, producing excellent thermal efficiency and very low emissions. The furnace is inherently low in NOx. This paper will provide both theoretical background and extensive operating results for this new melting concept. Applications describing both purpose built new furnaces and retrofits of existing reverberatory furnaces will be presented. Extensive operating emissions data will be presented.

Jan 1, 1996

By H. W. Becker, C. C. Frye, A. V. Degau, A. Masuda

Natural gas containing 25.65 per cent hydrogen sulfide and 4.75 per cent carbon dioxicle is gathered frorn eight \veih arid tratzsporrcd 26 miles at a flow rate of 160 MMcf/D and at operating pressures of frotrl 1,200 to 1,800 psig. Dry desiccant dehydrators at each wellsite tnaintaitz the dew point of the gas below 17F. Telemetering facililies permit control of field operations from a central instrunlent console. Corrosion control ineasures, design coilsiderations and material specifications pertainitz to these specia1 conditions are cliscussed. INTRODUCTION Natural gas containing 25.65 per cent H2S and 4.75 pcr cent CO, is produced from the Pine Creek field, Alta. It is dehydrated at wellheads, gathered at 2.200 psig and transported 26 miles to the Windfall field where it is delivered to the inlet of injection compressors at 1,800 psig. The daily average volume of gas transported is 160 MMcf. The project is believed to be unique in its combination of percentage of hydrogen sulfide, operating pressure and transportation distance. This paper describes the project and presents details of some of the design features, corrosion control program and centralized automatic operational control. The Pine Creek field project is one phase of a joint operation of two fields—thc other being the Windfall field. The two fields lie about 30 miles north of Edson, Alta. and 20 miles west of Whitecourt, Alta., respectively, as shown on the map (Fig. 1). They are owned by the same interests and operated according to a plan for maximum economic recovery of products. The Windfall Leduc D-3 reservoir contains a rich condensate-bearing gas containing 15.5 per cent HIS. The gas from the Pine Creek field contains only very small quantities of butane and heavier products. The Windfall reservoir is being cycled to obtain maximum condensate recovery using gas from the Pine Creek field as the displacing fluid, while producing the residue sales gas for both fields from the Windfall field. The Pine Creek field development and gas-gathering facilities are shown on the map (Fig. 2). The producing formation is the Leduc D-3 reef at a depth of 11,300 ft. The original reservoir pressure was 4,590 psia at 7,400 ft subsea and the temperature is 245F. Eight wells are equippcd with dry desiccant dehydrators with the following capacity ratings: three at 35 MMcf/D; three at 20 MMcf/D; and two at 10 MMcf/D. WELLHEAD EQUIPMENT Dry desiccant dehydrators were designed to reduce the water content of the saturated wellhead stream to 2.5 lb of water/MMcf at 2,000 psig. This specification was necessary to prevent hydrates and corrosion forming in the pipeline which will operate at temperatures as low as 20F. A typical flow diagram is shown in Fig. 3, and Fig. 4 is a photograph of one of the wellhead installations. Some of the design details given below are subject to modification in the field. The well-stream flowing temperatures range from 135 to 170F. Wellhead flowing pressures up to 3,200 psig are reduced to the dehydrator-operating pressure of about 2,100 psig by throttling through a pressure control valve. The gas is then passed through an aerial cooler where its temperature is reduced to 105F. thus removing over half

Declining metal prices over the last few years have reduced the number of new metallurgical plants being built and limited opportunities for introducing new processes. However, technological advances are still being made. With increasing economic pressures, the emphasis is now on reducing unit costs by making equipment larger and through use of technologies with lower operating costs. This trend can be seen in the increasing size of grinding mills and flotation cells used in recent plant designs and in the adoption of HPGR crushing as an alternative to SAG milling. Few new technologies achieve widespread introduction until there are clear economic or operational drivers. These might currently include: ò          increasingly stringent environmental standards; ò          availability of exotic materials for equipment construction; ò          increasingly sophisticated instrumentation and control systems; ò          the need to treat increasingly refractory oretypes; and ò          the length of supply routes to many new plants. As a result of these drivers, a number of new and revitalised technologies will get increasing prominence in the design of new operations, such as: ò          use of ultrafine milling equipment such as MIM's Isamill for treatment of refractory gold ore concentrates; ò          use of thiourea as an alternative for cyanide in sensitive locations; ò          novel hydrometallurgical routes for treating base metal ores in remote locations; ò          paste thickening for tailings deposition; and intensive cyanidation of gravity concentrate

Jan 1, 2000

By Bruna Silva de Almeida

Este trabalho apresenta o desenvolvimento do tratamento térmico de austêmpera em escala industrial do aço microligado ao Boro 22MnB5 da Companhia Siderúrgica Nacional – CSN, fornecido em bobina para o cliente Panatlântica para beneficiamento e posteriormente austemperado e testado em seu cliente Metal Mecânica Itália – MMI. Assim, descreve-se as etapas do processo de fabricação e caracterização do comportamento do material na aplicação em tiras austemperadas de aço na confecção de lâminas rotativas, que é um item importante na indústria de transformação de papel ondulado. O diferencial está na versatilidade desse aço, pois, apresenta boas propriedades de tenacidade, alta faixa de dureza e resistência ao desgaste, aliada a boa estampabilidade. Tal sucesso se deve a microestrutura bainítica e sua excelente ductilidade capaz de suportar as operações de estampagem após tratamento térmico.

Oct 30, 2017

By João Carmo Vendramim

A oxidação da superfície de peças, ferramentas, moldes ou matrizes construídas em ligas ferrosas tem larga utilização na indústria. As aplicações podem ser as mais diversas, tais como simplesmente atender às questões estéticas, proteção da superfície contra a corrosão, ou proteção contra a interação química com outros metais. Dentre as técnicas industriais utilizadas há o processo conhecido como “Oxidação Negra” que é realizado em baixas temperaturas, com imersão do aço da peça em óleo quente, ou banho de sal especial, ou mesmo a frio (soluções especiais). Outros processos utilizam fornos industriais com atmosfera de ar para aquecer a liga ferrosa até temperaturas da ordem de 500ºC e acrescentar (“pingar”) água como fonte de oxigênio. E em outros, aplicação ceras hidrocarbonetadas e ácidos inorgânicos e posterior oxidação [1] com aquecimento a temperaturas da ordem de 500ºC. Nesses processos, o objetivo é formar uma camada de óxidos tipos Magnetita e Hematita cujas características de menor coeficiente de atrito e determinadas propriedades físicas e químicas serviriam de barreira à interação química com outros metais em contato. A camada de óxido obtida nas condições descritas acima é bastante útil para determinadas aplicações industriais, tais como moldes de injeção de alumínio. Esse texto descreve o processo de oxidação desenvolvido utilizando a tecnologia de plasma.

Jul 30, 2018

By Edmilson Renato de Castro

Apresentam-se o processo e o protótipo de forno para a produção de ferro gusa por redução carbotérmica estimulada por micro-ondas de minério de ferro, na forma de pelotas auto-redutoras. O forno de redução com potência regulável de até 15 kW de micro-ondas de 2.45 GHz foi especialmente projetado e construído para este processo. A estrutura do forno é em aço inoxidável e utiliza três geradores de micro-ondas focados para o centro de um aplicador cilíndrico. Com esta configuração conseguiu-se produzir um campo eletromagnético de alta densidade energética. A carga de pelotas auto-redutoras, com massa em torno de 20 g foi reduzida em um cadinho de carbeto de silício. A montagem do forno dispõe de uma balança elétrica adaptada para suportar o cadinho de redução. O presente forno dispõe de controle e medida da potência fornecida e refletida, permitindo medir a energia de micro-ondas efetivamente aplicada à carga. Esta característica permitiu realizar balanços de massa e de energia além de determinar a evolução da taxa de reação através da medida contínua da massa das pelotas sob redução, ao longo do tempo de processamento. Obtiveram-se curvas cinéticas de redução carbotérmica de minério de ferro incentivada por micro-ondas e de seu consumo de energia durante o processo.

Aug 1, 2018

By K. J. Fair, G. Van Weert, J. E. Schneider

"IntroductionCyanidation is the principal process for extracting gold from ores . Many primary gold ores, however, are partially or totally refractory in the conventional cyanidation process.Considerable success has been achieved with new gold leaching techniques, such as intensive cyanidation, pressure cyanidation, carbon-in-leach cyanidation, etc. These techniques however, do not offer substantial gains in gold extraction from refractory pyrites.The more drastic pretreatment processes such as roasting, chemical oxidation, autoclave oxidation, and bacterial oxidation all utilize oxidation to break down the structures of pyrite and arsenopyrite. This generally renders the gold amenable to cyanidation.Comparative cost studies indicate that the oldest commercial pretreatment method, i.e. high temperature roasting, is currently the least expensive option if the sulphuric acid can be sold. It operates with air at atmospheric pressure and is characterized by fast reaction rates. For an alternative hydrometallurgical con centrate treatment method to be competitive, it too should operate with air at atmospheric pressure and with fast reaction rates. The NITROX process meets these conditions."

Jan 1, 1986

By William W. Edgerton, Moussa Wone, David H. Corkum, Carlton M. Ray

"The DC Clean Rivers (DCCR) Project is a 25 year, $2.6 Billion court ordered project to reduce combined sewer overflows (CSOs) discharging into the Potomac and Anacostia Rivers and Rock Creek, and also reduce flooding in the northern areas of the District of Columbia. Like all massive infrastructure programs, DCCR faced technical challenges, management challenges, risks of cost and schedule overruns, procurement challenges, and financing challenges. While DC Water is no stranger to large capital improvement projects (CIP), this CSO Program represents a once in a lifetime event for the Owner requiring the assembly of a single purpose team to implement. Some of the DCCR Project team’s most successful accomplishments to date are attributable to its introduction of early contractor involvement (ECI) to thoroughly vet the work from the perspective of the future constructors, development of functional baselines to share risks that are difficult to price and reduce reliance on geotechnical baseline interpretation during tunnel excavation, and attainment of financing through Municipal Century Green Bonds based on using design criteria of a minimum of 100 year life for the structures to establish intergenerational equity and fairness. This paper will discuss these innovations in detail and provide some sets of recommendations for the underground industry on when and how to use different approaches to better manage projects of this magnitude. INTRODUCTION The District of Columbia Water and Sewer Authority (DC Water) is an independent multi-jurisdictional authority that was established in 1996. Its primary mission is to provide water distribution services to more than 640,000 residents in the District of Columbia (District), and sewer treatment and disposal to 1.6 million residents of the District, Montgomery and Prince George’s counties in Maryland and Fairfax and Loudoun counties in Virginia."

Jan 1, 2016

By G M. Taylor

The application of high technology to monitor and control fire life safety, critical functionality in tunnels and underground spaces generally has progressed at an ever accelerating rate over the past decade. Today these systems comprise some of the most complex and little understood aspects of the tunnel/underground facility construction industry, with this area being perceived as high risk comprising impenetrably complex ‘black box’ technology covered in blinking LEDs. This paper will seek to explode some urban myths and common misconceptions associated with such systems, providing its intended audience with a review of what all this technology comprises and where the real risks lie in its delivery lie.The author contends (and looks to support such contention via this paper) that by applying baseline project and risk management processes to the procurement of this widely misunderstood black box technology, the quality of the final outcome can be much improved, driving innovation, reducing both cost and significantly mitigating delivery risk.CITATION:Taylor, G M, 2014. Procuring control and intelligent traffic systems for major new build projects – avoiding pitfalls and maximising value, in Proceedings 15th Australasian Tunnelling Conference 2014 , pp 113–120 (The Australasian Institute of Mining and Metallurgy: Melbourne).

Sep 17, 2014

By Alfredo Ramos Castro

La Cerro de Pasco Corporation se encarga de la producción de minerales como el cobre, plomo, zinc, plata, bismuto y algunos subproductos entre los que está en el cadmio, selenio y telurio. Entorno a esta panorama, surge la creación de la planta de cadmio que busca obtener dicho producto refinado en los precipitadores Cottrell y el residuo de purificación de la Planta de zinc, a partir de las materias primas el polvo de los hornos de plomo recuperado. En este sentido, el texto describe los procesos de producción de cadmio refinado que van desde la obtención de la materia prima hasta el moldeo del cadmio refinado para la venta.

Aug 20, 1963

By Marco Ojeda, Caio Moreira, Edelink Tinoco

Este documento técnico analiza la viabilidad del uso de un relave minero de la empresa Nexa Resources, cómo componente principal para la producción de cemento. El proyecto contempla dos etapas, en la primera etapa se acondicionan las proporciones de los componentes del relave mediante la flotación para en una segunda etapa hacer el tratamiento térmico del relave acondicionado y así producir el Clinker, que es la materia prima base que se usa para fabricar el cemento.

Sep 29, 2023

By Jairo Londono Arango

El presente texto realiza un diagnóstico sobre la producción y el mercado del carbón colombiano a través de los datos utilizados del último censo minero realizado en 1983, donde de describe los sistemas de explotación, nivel de tecnificación y los rendimientos alcanzados.

Jul 1, 1985

By J. C. Martin

A theoretical analysis of steam stimulation is presented for single sands. The analysis includes the effect of steam production and most of the effects of heat conduction. The results show the effects of a number of important variables on the performance of an idealized well under steam stimulation. Calculated responses are presented which indicate the effects of steam production, amount of steam injected, water production, formation thickness and formation damage. Results indicate that steam production can cause large reductions in the heat contained in the formation. This effect can be eliminated by drawdown control. Water production reduces the amount of oil produced during stimulation. The optimum amount of steam to inject depends on economic factors as well as the well response. In many cases, the increased temperature resulting from stimulation reduces oil viscosity near the well sufficiently to overcome the effects of formation damage even if the damage is not removed during steam injection. Calculated responses for thin sands are more favorable than anticipated. INTRODUCTION Little has been published on the theory of steam stimulation'-' despite the interest it has created and the wide variation in well responses. The results of the present analysis provide an insight into steam stimulation, and the methods employed provide a foundation for future work. Analyses presented in Refs. 1 and 2 are very limited and apply to gravity drainage conditions. Ref. 3 contains an analysis similar to the one presented here. The idealized models used and the assumptions made in Ref. 3 are different from those used in this paper. The analysis assumes that after steam injection has heated a small portion of the volume within the radius of drainage of a single uniform sand, a shut-in soaking period is allowed before returning the well to production. The effects of gravity, capillarity, transient pressure and water-sensitive sands are neglected. The injection and soaking times are assumed short compared to the stimulated production time. The initial temperature is assumed uniform; thus, the results apply primarily to first-cycle stimulation. The effects of gas production other than steam are neglected, and the water-oil ratio during production is assumed constant. Steam stimulation involves the simultaneous variation of the temperature, pressure and saturations. General mathematical equations for these variations are complicated and can be very difficult to solve. Simplified equations based on idealized models are used to reduce the mathematics sufficiently to allow approximate solutions to be obtained. DISCUSSION INJECTION An idealized model for which heat conduction is neglected is used to represent the behavior of a well during steam injection. The mathematics for this model is presented in Appendix A which also contains an approximate solution for the behavior of the no-conduction model. SOAKING During soaking, the well is shut in. Only the temperature, pressure and saturation distributions at the end of soaking are needed in the analysis. During soaking the heat is considered to be conducted in a uniform medium from an initially uniformly-heated circular cylinder confined to the producing interval. At the end of soaking the saturations and pressures are assumed to correspond to the cold zone. Analysis of the heat flow during soaking is included in the next section. The radius of the heated cylinder is calculated from the following heat balance (for constant quality steam injection). At the end of the soaking period it is assumed that little or no free gas is present near the well, and that the soaking period has been sufficiently long that the steam zone has had time to expand and the steam has condensed. The condition where there is no soaking is considered in the next section. PRODUCTION In this section, an approximate method is presented for solving the equations of heat and fluid flow associated with the production of oil and water during steam stimulation. Where initial pressure drawdowns are sufficient to cause steam to flow into the wellbore, steam production is assumed to occur within a short initial adjustment period (Appendix B). The production practices followed soon after the well is returned to production can have a large influence on the amount of oil produced during the stimulation cycle. Under most conditions, there is a period of time in which some or all of the water in the heated zone is converted into steam and produced. This flashing of hot water is caused by the pressure in the heated zone dropping below

By K. E. Brown, J. P. Brill, T. C. Doerr

A wide range of intermittent gas-lift tests way conducted in a 1,500-ft experimental well through 11/4- and 11/2-in, nominal size tubing. The well was equipped with two gas-lift valves, four Maihak electronic pressure transmitters and surface facilities to measure casing and tubing pressures, temperature, liquid production and the rate and volume of gas injected. For each tubing size, tests were conducted varying the slug length, gas volume injected and liquid viscosity and surface tension. From these tests, an empirical "fallback" or liquid loss correlation has been developed. No general fallback correlation could be obtained, and the correlation is presented in the form of one curve for each slug length of a given liquid and lubing size. A conceptual model has been developed which combines the fallback correlation with equarions which govern liquid slug pow. A mathematical simulation of the model in the form of a digital computer program is used to calculate total recovery, gas volume used and clearance time for a given test. Tubing pressures at the gas-lift valve and at the gm-slug interface are calculated as a function of time. Tubing pressures at the surface during slug clearance ore also calculated. The results compare favorably with the test data and verify the conceptual model. The extent to which the model can be used for other tubing sizes, depths, liquids and gas-lift valves can only be determined with additional experimental data. Data are also necessary so that a fallback curve can be constructed for the particular test conditions studied. INTRODUCTION The flow of liquid slugs in vertical conduits has long been an established production method in the petroleum industry. Under the name "intermittent gas lift", many advances have been made in engineering design. However, the unsteady-state nature of liquid slug flow has discouraged attempts to describe the problem analytically. The result has been that intermittent gas lift is dominated by rules-of-thumb engineering practices developed over many years. The advent of slim-hole completions has increased the demand for a more rigorous solution to the intermittent problem. Small-diameter conduits offer more frictional per intermittent cycle. Small-diameter conduits are defined to be 1%-in. nominal size tubing or smaller. When oil is produced from the reservoir in which it is found, and transported to surface tanks by intermittent gas lift, three separate flow stages are encountered: flow of the fluids to the wellbore through a porous medium, vertical flow of a liquid slug from the point of gas injection to the surface, and horizontal flow of the liquid slug through the surface flowlines from the wellhead to the surface tanks. The three stages are depicted schematically in Fig. 1. The present study deals with liquid slug flow in both the vertical and horizontal conduits, ending when the bottom of the liquid slug reaches the surface. Due to the large number of variables involved, the analytical study of intermittent gas lift is extremely complex. The possibility of flow regimes other than slug type, the nature of the force fields acting on the system, the interfacial instabilities involved, the varying operational principles of existing gas-lift valves and the complete unsteady-state nature of the physical phenomena occurring in an intermittent gas-lift cycle relate some of the difficulties encountered.

By T. C. Boberg, R. B. Lantz

This paper presents a method for calculating the producing rate of a well as a function of time following steam stimulation. The calculations have proved valuable in both selecting wells for stimulation and in determining optimum treatment sizes. The heat transfer model accounts for cooling of the oil sand by both vertical and radial conduction. Heat losses for any number of productive sands separated by unproductive rock are calculated for the injection. shut-in and production phases of the cycle. The oil rate increase caused by viscosity reduction due to heating is calculated by steady-state radial flow equations. The response of successive cycles of steam injection can also be calculated with this method. Excellent agreement is shown between calculated and actual field results. Also included are the results of several reservoir and process variable studies. The method is best suited for wells producing from a multiplicity of thin sands where the bulk of the stimulated production comes from the unheated reservoir. The flow equations used neglect gravity drainage and saturation changes within the heated region. INTRODUCTION This paper presents a calculation method which can be used to predict the field performance of the cyclic steam stimulation process. The calculation method enables the engineer to select reservoirs that have favorable characteristics for steam stimulation and permits him to determine how much steam must be injected to achieve favorable stimulation. While the calculation represents a considerable simplification of physical reality and the results are subject to numerous assumptions which must be made about the reservoir, it has been found that realistic calculations can be made of individual well performance following steam injection. The duration of the stimulation effect will depend primarily on the rate at which the heated oil sand cools which, in turn, is determined by the rate at which energy is removed from the formation with the produced fluids and conducted from the heated oil sand to unproductive rock. A complete mathematical solution to this problem is a formidable task, and finite difference techniques would undoubtedly have to be used. The calculation method pre- sented here utilizes analytic solutions of simple related heat transfer and fluid flow problems. The method is sufficiently simplified that it can be used as a hand calculation, although the calculations are somewhat lengthy and laborious. For that reason, the analysis was programmed for an IBM 7044 digital computer. Well responses observed at the Quiriquire field in eastern Venezuela&apos; have been matched using this program after making suitable approximations for reservoir and wellbore conditions. One of the most valuable uses of this calculation method is to assess the effect of reservoir and proc-cess variables on the stimulation response. This paper contains results of several studies made of key reservoir and process parameters. Among the most important of these is the influence of prior wellbore permeability damage. If a well is severely damaged prior to stimulation, a higher stimulation response will be observed than if it is undamaged. If a portion of this damage is removed, a permanent rate improvement will occur. THEORY I)ES(:KJJ&apos;TION OF CALCULATION METHOD The process of cyclic steam stimulation is essentially one of reducing oil viscosity around the wellbore by heating for a limited distance out into the formation through the injection of steam. Suitable modifications of the calculation technique presented here can be made so that stimulation of wells by hot gas injection or in situ combustion can also be calculated. A schematic drawing of the heat transfer and fluid flow considerations included in the calculation method is shown in Fig. 1. In brief, the calculation assumes that the oil sand is uniformly and radially invaded by injected steam. For wells producing from several sands, each sand is assumed to be invaded to the same distance radially. In calculating the radius heated rn energy losses from the wellbore and conduction to impermeable rock adjacent to the producing sands are taken into account. After steam injection is stopped, heat conduction continues and oil sands with r < ra cool as previously unheated shale and oil sand at r > r, begin to warm. The effect of warming of oil sand out beyond r, has little effect on the oil production rate compared to the effect of cooling of the oil sand nearer the wellbore than ra. Thus, in computing the oil production rate, an idealized step function temperature distribution in the reservoir is assumed where the original temperature exists for r > rn and where an average elevated temperature exists for r < rn. The average temperature in the oil sand for the region r < rn is computed as a function of

Jan 1, 1967

By G. W. Ostroot, S. Shryock

Cementing deep, high-temperature oil wells where static temperatures range from 350 to 400F has become routine in the part decade. In the United States there were 271 wells drilled deeper than 15,000 ft during 1963. Many of these wells had static temperatures higher than 400F. Bottom-hole static temperatures near 700F are now realities in the geother-mal (steam producing) wells of California&apos;s Salton Sea area. The detailed planning initiated prior to drilling the wells is discussed together with the methods, materials and equipment used in solving the cementing problems which are encountered. Data are also presented that lead to development of cementing compositions that provide adequate thickening time, do not retrogress in strength, and maintain low permeability under these extreme temperature conditions. Field data include the cementing programs used on eight relatively trouble-free geothermal steam wells in the Salton Sea area. INTRODUCTION Not too many years ago cementing oil wells with temperatures in the range of 300F caused considerable anxiety. In some areas of the United States it is now fairly common to cement wells having bottom-hole static temperatures in excess of 400F. We are now confronted with the problem of cementing wells with temperatures ranging from 500 to 700F. Temperatures in this order of magnitude are often found in geothermal steam wells. From where does this extreme heat emanate? There are many theories as to the source of this steam flow. The most widely held views are: (1) heat- ing of ground water fairly close to the surface by an intrusive mass of hot rock; (2) steam generation from a reservoir of metamorphic rock, normally found below 25,000 ft and not at the shallower depths of the Salton Sea reservoir; and (3) high-temperature gases (water vapor) escaping and migrating from molten or semi-molten rock (magma) at a considerable depth. Of these. No. 3 seems to be the most generally acceptable explanation. Heat from springs and fumaroles has been used for years as a means of heating and cooking; however, significant progress in harnessing the vast power of underground steam reservoirs has been relatively slow. The first large-scale attempt to use the heat generated by steam from wells was made in Italy around the beginning of the 20th century. In excess of 250,000 kw of electrical power is now being produced from holes around Larde-rello, Italy. Another very active drilling program was initiated in the volcanic area of New Zealand in 1949.&apos; Natural steam for power projects in the United States began in the early 1920&apos;s. An early commercial steam field is located at the Geysers, approximately 75 miles north of San Francisco, an area discovered in 1847 and used for many years as a health resort. Steam originates from 15 wells that have been drilled since 1957. The present output from this project is 25,000 kw. Success of the Geysers operation has been responsible for several companies taking a careful look at the feasibility of producing steam for power generation in the Salton Sea area of Southern California&apos;s Imperial Valley. Geothermal steam activity in this latter area began in 1961 when O&apos;Neill, Ashmun and Hilliard completed Sportsman No. 1, at that time the hottest wellbore in the world.&apos; Since its References given at end of paver. completion seven additional wells have been successfully completed in this area. Many problems encountered in drilling steam wells had to be overcome to make the ventures successful. Formation temperatures encountered in the Salton Sea seemed to be a straight-line function (a gradient of 13F per 100 ft of depth).&apos; This imposed severe conditions on all aspects of drilling and completion. This varied, to some extent, from gradients in the older geothermal areas. Not to be overlooked is the effect of these temperatures on casing creep or elongation by thermal expansion (Table I), because standard API flanged wellhead equipment makes no provision for this kind of performance. Floating equipment was redesigned, and changes in types of downhole equipment were made in an effort to eliminate anticipated problems. In the later completed wells, standard oil-well cementing equipment has been used. During the early development of geothermal steam wells there were some problems resulting from blowouts. However, these were eliminated in the deeper Salton Sea wells and no problems were encountered with the drilling mud. A sodium surfactant mud was used on the Sportsman No. 1 to drill from 2,690 to total depth. Nevertheless, it was necessary that a cooling system be added and the mud cooled before circulating it back into the well. The difficulty in evaluating the size of the steam area and its potential in terms of pounds of steam and years of productivity still has not been resolved. Economic complexities have also entered into the steam play in the Salton Sea. The wells at the Geysers were drilled at a cost of $15,000 to $20,-000, whereas the Salton Sea wells will cost more than $150,000. This cost differential has to some extent been accounted for because of the heavily

Jan 1, 1965

By B. G. Matson, M. A. Whitfield, G. R. Dysart

This paper describes the development of u computer program to calculate changes that occur in the length of tubular goods due to temperature and pressure changes during stimulation operations. Due to the numerous variables involved and the uncertainty of all static and dynamic conditions that could exist, it becomes a staggering task for individuals charged with completions to perform the necessary mathematical calculations. The computer program permits advance calculations for several sets of conditions. INTRODUCTION In the Delaware basin of West Texas alone, 50 wells were contracted or drilled to 15,000 ft or deeper in 1965. Deep well activity is continuing in this and other areas on an expanding scale. Many of these deep wells require extensive stimulation for successful commercial production, and during these operations, pressures and temperatures are encountered that have a pronounced effect on the length of tubular goods. This length change during a large-volume, high-pressure stimulation treatment utilizing fluids considerably cooler than bottom-hole temperature can be of such a magnitude that permanent damage to casing and tubing will result unless mechanical design, pressures and fluid temperatures are evaluated and controlled. These pressure and temperature effects can be calculated. However, the process lends itself well to computer solutions because of the mathematical nature of the problem and the calculating hours involved in arriving at an answer. The engineering-hour demand becomes more severe as tapered strings are involved. On initial treatments on a given well, surface pressure and injection rate conditions are unknown, and offset well conditions have not proven to be a reliable method for making predictions. For these reasons, it has become rather standard procedure for operators to compensate for these uncertainties by placing unnecessary pressure and fluid temperature restrictions on stimulation design. On a number of occasions treating fluids have been preheated to as much as 160F as a means of compensating for thermal contmction resulting from pumping cool fluids. The maintenance of packer seals has been treated by Lubinski, Althouse and Logan&apos;,&apos; and the problem of therma1 effects on pipe has been explored by Ramey." These works were expanded and the results made applicable to everyday oilfield terminology before submitting them to computer programming. The pressure and temperature effects on tubing movement previously mentioned occur simultaneously as fluid moves through the pipe. The pressure changes, for purposes of explanation, are categorized here as to the various effects these pressures have on a tubing string. These divisions are (1) the piston-like results of forces acting on horizontal surfaces exposed to pressure, (2) swelling or ballooning of the tubing along its entire length due to the forces of pressure acting against the tubing walls, (3) the elongation of tubing due to frictional drag and (4) corkscrewing of the pipe due to internal pressure. Thermal changes are also of great importance, as their results may be more significant than any of the pressure effects. Steel is an excellent conductor of heat and the earth is a relatively poor conductor. It has been calculated that pipe temperatures at depths of more than 20,000 ft approach within as little as 25" the temperfature of the surface fluid after pumping for 2 hours, or a drop in temperature in some treatments of more than 220F. The equations presented in this paper were developed for computer programming and simplicity of input information; therefore, numerical constants such as Young&apos;s modulus for steel (28 X 10\ si), the coefficient of thermal expansion of steel (6.9 X 10."IF) and Poisson&apos;s ratio for steel (0.3) are included with unit conversion factors. The moment of inertia of tubing cross-sectional area with respect to its diameter was changed to a constant times (D&apos; — d&apos;) where D is outer diameter and d is inner diameter. Units in the equations are length in feet, diameter in inches, density in pounds per gallon, pressure in psi, rate in barrels per minute and time in hours. PISTON-LIKE REACTIONS A change in tubing internal dimensions and the exposure of other horizontal surfaces to different pressures on the inside and outside of the tubing result in a reaction much like a piston under pressure. Such is the case when the internal diameter changes in a combination string of pipe, when seals of a slick joint assembly are subject to pressure and in the end effects of a tubing string. The change in tubing length due to the piston effects of a slick joint packer is affected by the various diameters involved, the tubing pressure Ap,, the casing pressure ,Ap,, length of pipe L, densities of fluid in the tubing before and during pump-

By S. G. Gibbs, A. B. Neely

Jan 1, 1967

By H. A. Lesser, H. L. Stone, G. H. Bruce

ESSO PRODUCTION RESEARCH CO., HOUSTON, TEX. A mathematical model that represents the conduction heating of a rock formation of limited permeability is formulated. Heat is introduced by the injection of a hot condensing gas into horizontal fractures through the formation. The fractures are assumed to be equally spaced; the flow of fluid is linear. The model consists of three coupled partial differential equations and two functional relationships. Temperature histories for both fractures and formation are obtained by numerical procedures. Application of the model in predicting in situ heating of oil shale is illustrated with four sample cases. Influences of shale thermal diffusivity, fluid pressure in the fracture and fracture spacing upon heating rate are demonstrated. In all cases considered, several years were required to heat all the formation to 700F with 1,000F steam. Less than 32 per cent of the injected heat was utilized for heating the shale. To facilitate extensive calculations of this type, a set of seven dimension-less quantities are derived. With this dimensionless system, the effect of controllable parameters on economics can be explored. INTRODUCTION Vast deposits of hydrocarbons are contained in oil shale formations in the western United States and in other countries. These hydrocarbons, known as kerogen, are difficult to recover because they are immobile solids and because the rock formations in which they are found have very limited permeability. The kerogen can be converted through pyrolysis to recoverable liquids and gases if the formation temperature is elevated to the range 600 to 800F. To accomplish this heating, the formation might be artificially fractured and a hot fluid injected into the fractures. If the injection and production wells are vertical and the fractures horizontal, interwell communication will be established and the hot fluid will flow from an injection well to a production well. In this process, some of the heat in the fluid will be given up and conducted into the formation. Products of pyrolysis will flow from the heated rock matrix into the fractures and be produced, commingled with the injected fluid. The practicality of such a process is strongly influenced by the rate at which heat can be transferred from the hot fluids to the formation. An analysis of this heat conduction problem is the subject of this paper. Linear flow of a condensing gas through a set of horizontal, equally spaced fractures is considered. Temperature histories for both fractures and formation are obtained from numerical procedures. The analysis also applies to formations containing streaks of natural permeability instead of fractures. Heat flow problems similar to the one treated here have been studied by other workers. Thomas1 has solved a radial problem in which he considers the injection of a noncondensing gas into a single, horizontal fracture and approximates the temperature profile in the fracture by a step function. The solutions to other problems, which are less similar to the present problem than the one treated by Thomas, have been reviewed by Spillette.2 In addition to these mathematical studies, a field test of an in situ shale oil recovery process using hot natural gas as the injected fluid has been reported.3 The first part of this paper is concerned with the mathematical development of the problem. The differential equations, boundary conditions and functional relationships which describe the physical model are formulated and the equations are cast into finite difference form. The method of solution of the difference equations is discussed (Appendix B). The second part of this paper presents results computed for a typical oil shale formation for which steam at 1,000F is the injected fluid. Fracture spacing, horizontal and vertical thermal diffusivities

Jan 1, 1967