bluuebunny/crossref_metadata_2025 huggingface dataset:
Representation of Gas-Condensate Wells in Numerical Reservoir Simulations
Authors: Panfilova I. , Panfilov M.
Published: December 2007

We have developed a new analytical method, allowing to relate wellbore and wellblock pressures, saturations and concentrations, in case of the multicomponent mixture flow with phase transitions. The saturation distribution near a well is shown to be governed by a fractional power-value logarithmic law. Moreover, the simple logarithmic approximation for pressure field may be invalid near the well. The relationships for integral parameters of a well, such as the productivity index and the transmissibility for each fluid phase and each chemical component, have been deduced. Non-trivial physical effects were shown. Certain instability caused by inversion of phase transitions could be observed, that result in oscillatory modes of well production.

Introduction

In reservoir simulation, the linear approximation for computed functions becomes non-valid near wells. The more complex approximations using the natural laws of the function distribution near the well have been proposed in case of one- and two-phase flows without phase transition. In case of compositional flow with phase transitions similar to gas-condensate mixture, the problem becomes more important, because the difference between wellbore and wellbloc saturations can be very large. The exhaustion of gas-condensate field may be divided on two time stages, where the process is described by different system of equations. The first stage corresponds to transient process of perturbation propagation from wells. Methods determining the wellbore saturation and concentrations for this time stage have been developed. In this paper, the same method is extended on the second stage, where the liquid flow takes almost steady-state behavior.
Optimization of Pipeline Network in Metropolitan Area, Korea, with Hybrid MCST-CD Networking Model
Authors: Sung W. , Lee J. , Huh D. , Kwon O.
Published: December 2007

This paper presents a hybrid network model(HY-PIPENET) implementing a minimum cost spanning tree(MCST) network algorithm to be able to determine optimum path and constrained derivative(CD) method to select optimum pipe diameter. The HY-PIPENET has been validated with the published data of 6-node/7-pipe networking system, and also this system has been optimized with MCST-CD method. As a result, it was found that the gas can be sufficiently supplied at the lower pressure with the smaller diameters of pipe compared to the original system in 6-node/7-pipe network. Hence, the construction cost was reduced about 40% in the optimized system. The hybrid networking model has been also applied to a complicated domestic gas pipeline network in metropolitan area, Korea. In this simulation, parametric study was performed to understand the role of each individual parameter such as source pressure, flow rate, and pipe diameter on the optimization of network. From the results of these simulations, we have proposed the optimized network as tree-type structure with optimum pipe diameter and source pressure in metropolitan area, Korea, however, this proposed system does not consider the environmental problems as well as safety concerns.
Use of a Pseudosteady-State Solution to Predict Productivity of a Fractured Well with Spatially Varying Fracture Geometry
Authors: Lee Kun Sang
Published: December 2007

An infinite- or finite-conductivity vertical fracture intersecting a well produced at a constant rate within a closed system is considered. Fracture is modeled as a vertical slab with lengthwise variation in the fracture geometric properties. The long-time inflow performance is obtained from a finite-element solutions of pseudosteady-state diffusivity equation, which considers fixed flux over all reservoir region.

The first part of this paper examines the behavior of an infinite-conductivity fracture. Comparisons of well productivity calculated with transient and pseudosteady-state solutions show a good agreement. Computations for anisotropic reservoirs were made to examine the effects of reservoir permeability anisotropy and fracture length on the late-time pressure response. It is demonstrated that well productivity is heavily dependent on the fracture orientation and main flow pattern. The second part investigates the effects of fracture permeability on the pressure response of a finite-conductivity fracture. The fracture conductivity is a decreasing function of distance from wellbore.

The new fracture model and solution technique provides more realistic description for fracture geometry and long-time pressure response with a minimum computational effort.
Fluid Diversion to Improve Well Stimulation
Authors: Gallus Julius Peter , Pye David Stephen
Published: December 2007

A review of diverting is made with primary emphasis on granular diverting agents, and wax-polymer diverting agents in particular. The results of laboratory tests are given. Numerous field tests are reviewed, including we!! production data. Both the laboratory and field tests production data. Both the laboratory and field tests show the wax-polymer agents to be the best of the diverting materials tested. The wax-polymer materials are also oil soluble, which will prevent formation damage.

Introduction

Designing treatments for the stimulation of low-productivity oil and gas wells by acidizing, hydraulic fracturing, and injecting organic solvents or surface-active chemicals is an important function of the modern petroleum engineer. These well-treating processes are well established today. However, in many cases achieved success ratios leave much to be desired. Analysis of job failures shows that all too frequently failure may be attributed to poor treating-fluid distribution. Failure to effectively divert treating fluids from thief zones results either in no treatment or poor treatment of the producing interval.

Thief zones can result from any number of causes, a principal one being nonhomogeneous formations. Producing principal one being nonhomogeneous formations. Producing formations penetrated by oil and gas wells range from 3 to 3000 feet in thickness. As a rule these zones are profoundly inhomogeneous, discontinuous and variable in profoundly inhomogeneous, discontinuous and variable in permeability, sometimes from centimeter to centimeter. permeability, sometimes from centimeter to centimeter. Fluid flow surveys within wells have shown that production from and injection into permeable zones frequently occur in only 10% to 15% of the productive interval. Besides inhomogeneities, variable flow potentials can also be caused by damage to part of the formation. In view of what is known about formation and perforation damage, this is not too surprising.

Productive formations, particularly sandstone formations, act essentially as filters. We know that filters become plugged with time, and we expect them to become plugged, it would appear reasonable to say that we should similarly expect formation rock to decrease in permeability as large volumes of crude oil and brine permeability as large volumes of crude oil and brine which carry solids are filtered through it into the wellbore.
Performance Evaluation And Formation Damage Potential Of New Water Based Drilling Formulations
Authors: Argillier J-F. , Audibert A. , Longeron D.
Published: December 2007

Water based drilling fluid formulations have been recently adapted to new drilling technologies and environmental concerns. This involves selection of specific additives that prevent problems encountered when drilling slimhole, high temperature wells or inactive clayey formations. Formation damage risks are well documented for standard mud formulations but they are poorly analysed for new types of non polluting muds. This paper describes extensive laboratory work aimed at evaluating the behavior of these new types of mud formulations. First, static and dynamic filtration experiments were conducted on paper filters and rock slices. Examination of mud cakes by means of cryo-SEM has permitted to correlate filtration behavior with structural characteristics of both external and internal mud cakes. Then, the simulation of the full process of mud invasion in oil-bearing reservoirs was achieved by performing static and dynamic filtration experiments in a specially designed core-holder cell containing 40 cm long sandstone core samples. Cumulative filtrate losses and pressure drops across six sections of the core while circulating the mud and back flushing the oil were continuously monitored to evaluate the permeability damage. Damage arising from overbalanced conditions has been evaluated in terms of cake permeability, fluid loss characterization, reduction in oil permeability after mud exposure. For the three mud compositions tested here the filtration process in high permeability sandstones is mainly controlled by external mud cakes. Damage is severe but an additional damage due to the trapped aqueous filtrate phase can strongly affect the oil relative permeabilities. This approach has given a complete behavior understanding of new water based drilling formulations including evaluation of their performances, limits of use at high temperature and assessment of risks for different operational conditions.
Development of a Recommended Practice for Formation Damage Testing
Authors: Marshall David S. , Gray Russell , Byrne Michael
Published: December 2007

Well productivity can be significantly affected by damage to the near well-bore area caused during drilling in the reservoir section of a well. Historically, the use of perforated completions allowed for penetration of the producing formation beyond the damaged area but the recent trend towards non-perforated completions has resulted in an increased emphasis on damage minimisation. This, in turn, has increased the importance of evaluating drilling fluids and completion techniques used from a reservoir damage perspective. The suitability of a drilling or completion fluid for use in a particular reservoir can, and should, be determined using the measurement of return permeability or some other indication of formation damage. A major factor which limits this practice is that no industry standard equipment or methodology exists for this type of testing and differences in results obtained at different times or in different laboratories cannot be reliably compared. Repeatability and reproducibility of the tests conducted have not been widely established. In order to address these problems, a recommended practice for formation damage testing has been developed which covers all aspects of the test methodology from core selection and preparation to the writing of the final report and interpretation of the results. By standardising on equipment and methodology, it has been possible to establish the degree of variation which can be expected when the same samples are tested in the same way in different laboratories. Further testing in which selected parameters have been varied has also given an indication of the degree to which the setting of these variables affects the final result. It is hoped that this recommended practice will now gain acceptance throughout the industry and that the process of evaluating fluids for formation damage potential will become simpler and more efficient through tie greater use and validity of comparisons between data from different sources.
Biotechnological Treatment Removes Xanthan-Based Skin Damage
Authors: TjonJoePin Robert M. , Beall Brian B. , Brannon Harold D.
Published: December 2007

Conventional reservoir drilling fluids typically consist of xanthan-based polymers to optimize recovery of drill cuttings and reduce friction or torque during the drilling operations. Previously conducted laboratory studies have indicated that the damage produced by these types of xanthan-based drilling fluids can be easily removed. Field data, on the other hand, has indicated that substantial amounts of polymeric damage remain in the formation. Even though these psuedoplastic, non-thixotropic, xanthan-based drilling fluids exhibit low shear rheologies during the operations, they can contribute to tremendous amounts of skin damage. This insufficient degradation of filter cake may impede flow and dramatically reduce formation permeability hence well productivity.

Recent extensive research was conducted to develop a treatment which could effectively reduce this type of polymeric damage. A novel biotechnological treatment has been developed, which effectively removes xanthan-based filter cakes or skin damage at temperatures from 70 °F to well over 250 °F.

Core flow evaluations have shown that multi-fold improvements are achieved with this optimized biotechnological removal treatment. A detailed study of the laboratory and field case histories are presented. Average incremental production rates of the treated wells were significantly improved, clearly demonstrating the effectiveness of this removal system.
Revolutionary New Chemical Delivery System for Fractured, Gravel Packed and Prepacked Screen Wells
Authors: Webb P.J.C. , Nistad T.A. , Knapstad B. , Ravenscroft P.D. , Collins I.R.
Published: December 2007

Laboratory tests and a field trial have demonstrated the technical and economic benefits of a revolutionary downhole chemical scale inhibitor delivery method. The method also has the potential to be used for other oilfield chemicals, for example corrosion inhibitors and gel breakers.

The method involves the controlled release of chemical from impregnated porous ceramic beads, manufactured with the necessary mechanical strength and size properties for direct substitution of proppant, gravel pack sand and prepacked screen beads.

This novel concept offers an economically attractive method of chemical delivery for both advanced wells and conventional wells when compared to conventional intervention based delivery techniques, such as squeeze treatments. The concept addresses many of the operational problems associated with chemical treatment of wells completed with multiple fractures, long horizontal sections with unfavourable pressure regimes, remote wells with high intervention costs, and multi-lateral type completions. In general, the concept offers reduced deferred oil costs through reduced well intervention and preservation of pack conductivity, and more efficient chemical use compared to squeeze technology.

Wells with fractures containing in excess of 100,000 lb of proppant have the potential for scale inhibitor treatments lasting a significant proportion of a wells lifetime. Prepacked screens containing 3,000 lb of chemically impregnated bead could provide treatment periods of 2 to 36 months.

Introduction

The deposition of mineral scales, such as carbonates and sulphates, in oil producing wells is a recurring operational problem for conventional and advanced wells. Significant operational costs are incurred when applying preventative or remedial scale control strategies, for example chemical scale inhibitor squeeze treatments or re-perforation, respectively. This paper presents technical and economic details of a revolutionary method of scale inhibitor delivery developed by AEA Technology with the support of Saga Petroleum ASA, Norsk Hydro ASA, and BP Exploration Operating Company Ltd. The delivery concept has many advantages when compared to conventional scale control strategies, as applied to advanced and conventional well completions. The potential for applying other chemical types is briefly discussed. The method of delivery is applicable to production wells completed with propped fractures, gravel packs, prepacked screens, and other intermediate types where beads or proppant are placed in a well.
Use of a Simple Mathematical Model for Estimating Formation Damage in Wells Intersecting Long Fractures
Authors: Guo B. , Schechter D. S.
Published: December 2007

A newly developed mathematical model has been used for formation damage analyses of two hydraulically fractured horizontal wells in the Daqing field, China, and twelve vertical wells in the naturally fractured reservoirs of the Spraberry Trend Area, West Texas. Application of the model to Daqing horizontal wells indicated that these wells should have 4 to 5 times higher oil production rates if the formation was not damaged. The use of the model has captured the characteristics of rapid decline in productivity of the Spraberry vertical wells. Comparisons between the effects of matrix skin and fracture permeability indicated that stress-sensitive fracture permeability is responsible for the productivity loss of these wells. This paper provides reservoir engineers with a practical tool for analyzing inflow performance of wells intersecting long fractures.
A Novel Dual Injection System for Water Shut-Off Treatments
Authors: Plahn S.V. , Stevens D.G. , Enkababian P.G. , Anyan S.L. , Feraud J.P.
Published: December 2007

There are numerous water shut-off techniques available. One of these is to permanently seal watered-out zones with rigid, polymer gelants. This method can be very effective for near-wellbore water flow problems provided the gelant only enters the watered-out interval and does not damage nearby productive pay. Gelant placement can frequently be controlled using mechanical devices such as packers and bridge plugs. However, many times, gelant may still enter productive pay through flow paths outside the casing. For such cases, mechanical isolation within the well may not suffice - especially if crossflow between zones is high. In this paper we discuss a specialized gelant placement technique, referred to as dual injection, that can be used to address these types of water control problems. Dual injection can be implemented several ways. We discuss some of these, as well as a completely new dual injection system.

Introduction

Numerous techniques exist for solving water production problems. These range from simple mechanical means such as bridge plugs and casing patches, to more elaborate schemes involving downhole separation, dual production, and horizontal drilling. Injection of polymer gelants is also a widespread practice.

Polymer gelants can be deployed a variety of ways. By far the most pervasive is to pump down the existing production tubing without any zonal selectivity (viz., "bullheading"). This procedure is operationally attractive because it is easy to implement and treatment costs are comparatively low. However, gelant is distributed among all perforated zones. This is undesirable because many gelants - particularly those intended for near-wellbore applications - will indiscriminately and permanently damage all porous media when gelation or setting occurs.

Mechanical isolation of perforated intervals with packers and bridge plugs, or sand/calcium carbonate fill is preferred over bullheading. Often however, flow can still occur between perforated intervals through flow paths outside the casing. In such cases, mechanical isolation may not suffice. In this paper we will discuss a specialized placement technique, referred to as dual injection, that can be used to address water control problems in such cases.
Water Control by Bridging Colloids
Authors: Zitha Pacelli L. J.
Published: December 2007

This study explores the potential of dual polymer-colloid systems to improve polymer placement. The approach consists of an analysis of microscopic flow aspects. We show that dual bridging adsorption of polymer-colloids may occur similarly to that of polymers alone. However, in the former case, the ensuing permeability reduction is much stronger. Therefore, dual polymer-colloid adsorption may improve considerably polymer placement.
Field Testing A Front-Mounted Mechanical Oilfield Pumping Unit
Authors: Byrd J.P. , Jackson B.C.
Published: December 2007

Publication Rights Reserved

Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and considered for publication in one of the two SPE magazines with the paper.

Several major oil companies have made recent, head-to-head studies comparing the mechanical properties of a front-mounted, non-symmetrical mechanical pumping unit to those of its well known conventional counterpart. The results of there tests have shown that in many applications, the lower torsional and structural loading of the front-mounted unit allows the operator to use smaller and less expensive equipment to handle the same fluid loads. This paper includes one of these recent, representative, oil company studies and its conclusions.

During the latter part of 1956, a front-mounted, non-symmetrical, mechanical beam-type pumping unit was developed for general oilfield service. This machine was designed for the same wide range of application covered by the standard or conventional surface pumping unit. Although this new pumping system employed the same general structural components, its mechanical characteristics, and hence, its functional ability, were substantially different from those of the conventional unit.

The difference in the mechanical properties of the new machine was produced by a re-arrangement of the components of the conventional unit. This changed it from a symmetrical Class I lever system [fulcrum at mid-beam] to a non-symmetrical Class III lever system [fulcrum at rear beam]. The well load and counterbalance torque were dephased by providing an angular off-set in the crank, and moving the gearbox away from the well a proportionate amount, while driving the machine in a particular direction of rotation.

This front-mounted [Class III lever] unit [Fig. 1] combines the simplicity, ruggedness, and high efficiency of the conventional unit, with the beneficial rod motion and ease of counter-balance of the air balanced system, and provides, in addition, a relatively uniform torque demand on both primer mover and gear reducer.

This new Class III geometry makes possible several desirable pumping unit properties:A simple means of presenting the normal rod load variation of each pump stroke as a relatively uniform torsional load to both gear reducer and prime mover. By smoothing out these peak torsional loads it is often possible to use a smaller gear reducer and prime mover to handle a given application.A method of lifting rods and fluid with lover upstroke acceleration so that in many cases the peak polished rod load is appreciably reduced. This property not only tends to minimize rod loading but it also tends to minimize production losses because of reduced rod maintenance.
A Predictive Method to Estimate Remaining Gas Reserves and Future Prospect Outcome Probabilities
Authors: Zorbalas K. , Rogers R. E.
Published: December 2007

In trying economic times when exploration budgets are cut, a partially explored basin can experience a slowdown in activity, leaving us questioning whether sufficient reserves remain to justify further exploration.

In such situations a clear idea of the basin's potential is necessary in order to continue drilling new wells. A series of studies was undertaken and probability plotting was used to analyze the Black Warrior basin of Mississippi for the number and size distribution of undiscovered natural gas reserves.

Part of the study was the use of decline curve analysis to predict ultimate gas reserves from 256 active wells in the basin. A recovery factor as a function of depth for the Warrior gas fields was developed. Original gas in place figures were calculated using the recovery factors and the predictions of ultimate reserves. It was found that the ultimate reserves by field in the Black Warrior basin are log-normally distributed.

By using probability plots in any partially explored basin, one can foresee the economic justification for further exploratory drilling. This method is the most thorough and informative technique that can be applied to a basin which has a proven potential of future discoveries. As exploration becomes more selective, this technique could become a valuable tool to many exploration programs.
Argentine Gas and Electricity markets - Energetic Integration in South America
Authors: Markous Ricardo M. , Ridelener Daniel A.
Published: December 2007

Argentine Gas and Electricity markets - Energetic Integration in South America.

This paper is aimed at showing the favorable conditions of the argentine energetic market with respect to exports. Both the electric and gas markets are analyzed after the significant changes they have undergone since 1991/1992. And finally we analyze, the chance of an energetic integration and the information about several projects under study.

Introduction

1991 was a year of essential changes in the electric market. A mainly state owned centralized management of generation resources switched to an open regulation system divided into three basic areas: generation, transmission and distribution; the subsequent deregulation of the first of these areas created competitive conditions within the electric industry. Additionally several effects are having a great impact in the development of the electric market:–Due to the absence of the state as an investor and to the remarkably high investment costs required to face hydroelectric projects, apart from Yacyreta, there are no significant projects in the market,–The contracts granted in the privatization of the big Power plants turned out to be an uncertainty factor as regards their expiration. Thus, generators face two alternatives: either they re-equip to be able to achieve an efficient competition level or they run the risk of being left out of the market.–There is an important fall in gas turbines and combined cycle units prices.

A similar analysis can be made of the gas industry. Before the privatization of Gas del Estado, Argentina's state owned gas transportation and distribution company, the gas pipelines in the country worked with a high load factor. New transportation capacity was available just to supply Residential peak demand, fact which was not always achieved. Out of the winter period, idle capacity was used to supply power plants.

As from 1993 and specially during 1994 and 1995 there was a significant increase in transportation capacity, mainly due to the obligation of the distribution companies to supply their non-interruptible customer, to keep minimum standards of service, and to the demand of industrial consumers and power plants for "no-cut off" firm capacity.

This resulted in a significant increase in transportation capacity, a lower load factor, and more availability of gas for the electric industry.

We should also underline that since May 1994, the price of gas at well-head was deregulated, encouraging the search and development of new reserves.

The first part of this paper will show in detail the growth of the electric market, the higher availability of gas for it, how some of the above mentioned issues interrelate and the effect that competition in the electric market will have in the coming years.

The second part of this paper analyses the possible energy complementation among the Southern Cone countries, and the advantages of some of the integration projects currently under way.
Gaz De France Experience in Underground Gas Storage
Authors: Hugout B.
Published: December 2007

Like in most of the developed gas consuming countries, the French natural gas consumption varies greatly according to the day and the season. The distribution system alone, from producer to consumer, cannot provide all the flexibility required to handle such fluctuations, due to constraints arising from natural gas purchase agreements and the technical possibilities of processing, liquefaction, and transmission facilities.

As early as 1954, Gaz de France developed underground gas storage facilities for natural gas. These facilities have proven to be the only effective way to store the large volumes of gas required. For forty years, these facilities have fully lived up to their potential with confirmed high performance They have also demonstrated that they are environmentally safe and reliable.

In 1997,15 facilities are operated in France: 12 in aquifers and 3 in salt caverns. Their working gas capacity. 11 BCM, represents roughly one third of France's annual consumption. Two new facilities, one in a large aquifer in Aquitaine and one in a gas field operated by GDF in the East part of the Paris sedimentary basin since 1994, will be commissioned early 21st century.

To carry out its facilities development program. GDF lias made continuous R&D efforts. In so doing, it lias acquired a level of know-how that is acknowledged world-wide and benefits its subsidiaries and joint companies all over the world. New R&D projects aim at optimising the performances of the existing facilities, reducing the capital and operating expenditures for the further facilities, and developing unconventional facilities close to the areas of consumption even in unfavourable geological conditions.

Looking back upon long-standing construction and operation experience at more than twenty storage facilities throughout the world, thanks to its subsidiaries. Gaz de France is willing and able to become an industrial partner in storage facility projects which will be necessary for the future development of natural gas in all its uses.
Mineral and Energy Economics - A Milestone in "Mines" Dynamic Educational Program
Authors: Pederson John A. , Rudawsky Oded , Butler J. Samuel
Published: December 2007

The accelerated pace of applying modern technology to improve production has been well demonstrated in the energy field and particularly in the petroleum industry during the past two decades. The change in productive capability has been manifested in expanding markets, new sources of supply, and increasing demands. As a result the impact on the markets, especially in the form of substituting one source of energy form for another, has been significant. There have also been significant changes in the regulations and procedures used to guide businesses', changes that include financial reporting, tax laws, regulatory agencies, authority and responsibility. Such changes suggest that a study of the underlying concepts of market structure, as well as the financial and business implications of improving technology is in order. This study would enable the economy to make better use of the more complex technology currently available. There is a necessity for the development and use of more advanced economic methodology to keep pace with technical progress. This methodology must be such progress. This methodology must be such that it evaluates costs and results in a manner that is consistent with both short- and long-run objectives of firms.

The Colorado School of Mines, having recognized the changing and increasing role of technology in the mineral industry, has successively introduced new programs since the school's inception. As part of this policy, the Department of part of this policy, the Department of Mineral Economics was established in the Fall of 1969.

The Department was charged with an expanded program of undergraduate and graduate courses in economics, management, and mineral and energy economics. A graduate program on the Master of Science level in Mineral Economics was instituted at the same time. This graduate program was designed to enable individuals with a background in the mineral field to recognize and evaluate the relevant economic factors of the extractive industry.

Introduction

In a paper on the subject of the energy crisis, recently presented before the Society of Petroleum Engineers, Mr. Lawrence O'Connor, Jr., of the Federal Power Commission, stated that everything Power Commission, stated that everything that could go wrong within the energy industries has gone wrong. The situation referred to is the apparent simultaneous shortages that all supply sources of primary energy are facing. The failure of primary energy are facing. The failure of nuclear energy to meet projected time-tables, as an example, necessitates continued reliance on hydrocarbon products to supply most of the nation's primary energy.

The continued reliance on these energy resources may pose many problems in the near future, and apparent shortages is the most serious one.
Statistical Characterization of Metal-Contaminated Fills
Authors: Patzek Tad W. , Sullivan Patrick J.
Published: December 2007

We present a simple and easy to implement statistical method of estimating masses of metal contaminants in a shallow industrial fill. The current metal concentrations are assumed to have resulted mostly from random mixing, crushing and placement of the fill. With this assumption, it can be shown that the metal concentrations should be lognormally distributed, i.e., the distributions of the concentration logarithms should be normal. The properties of the lognormal distribution are then used to calculate the expected masses of zinc, lead, barium, cadmium, copper, antimony and mercury in the soil. In addition, a neural network/statistical model is used to account for a possible spatial nonuniformity of metal concentrations. The neural network model predicts the total metal masses within a factor of two from the lognormal model. This means that a significant spatial nonuniformity exists in the fill, but more work is needed to validate the neural network model.

Site History

The site (Fig. 1) is located in the San Francisco Bay region and occupies an area of roughly 500 by 600 ft. Although the site is approximately a quarter mile from the Bay, in the 1870's, it was mostly a tidal flat. During this time period, only the northern corner of the site was above sea level.

Lead smelting and refining operations began in 1872 on the dry land portion of the site. From 1872 through 1905, the operations at this site manufactured lead bullion, gold, silver, white lead (lead carbonate) and quicksilver. Smelting and refining required the storage and processing of ores that contained Arsenic (As), Antimony (Sb), Copper (Cu), Gold (Au), Lead (Pb), Silver (Ag), Sulfur (S), and Zinc (Zn). The major economic mineral in the ore processed at this site would have been Galena (PbS). The smelting process, generated both solid wastes which contain the elements listed previously and acidic air emissions that typically contain sulfur, lead, arsenic and antimony.

The solid waste generated at the site during this period of operation was dumped into the adjacent tidal flat as fill. As a result, the fill is a heterogeneous mixture of waste rock (or gangue minerals) and the following smelter wastes,Speiss, a combination of arsenic or antimony and metallic iron;Matte, consisting chiefly of a combination of sulfur and iron;Slag, which is partly a chemical and partly a mechanical mixture of melted gangue and waste matters contained in the ore and fluxes; andFlue dust, consisting mostly of the finer particles of ore and fuel.

By 1907, three-quarters the site had been filled, with only the southern quarter of the site still below sea level. At this time, the site had been converted to the manufacture of sulfuric acid from the roasting of pyrite (iron sulfides). The pyrites that were roasted at this facility contained percent levels of zinc and copper and trace amounts of arsenic, cadmium, lead and silver.

P. 445^
Performance Analysis of Polymer Injection On Pilot Scale: A Case History
Authors: Sharma S.K. , Singh S.K. , Dayal H.S.
Published: December 2007

Polymer flooding on pilot scale in an inverted, asymmetrical five spot pattern had started in Sanand field of ONOC, India in 1985 and has completed recently. The reservoir is made of silty sand stone at a depth of 1300 m containing oil of 20 cp viscosity at 85 C (reservoir temperature). Average permeability in the pilot area is 1000 md and average sand thickness is 7 m.

Polyacrylamide polymer was used for injection on pilot scale. Polymer concentration of 400 ppm and 15 % pore volume of slug size was chosen for field injection on the basis of laboratory experiment, However, during polymer injection an average concentration of 440 ppm was injected. A total of 94,408 m3 solution containing 41,758 kg of dry polymer was injected through one well in 55 months and response was analyzed in terms of tracer and polymer break through, decline in salinity, improvement in rate etc. Being first project of its kind in the country extra care was taken in handling polymer and other chemicals in the field.

Injection response in terms of polymer breakthrough, decline in produced water salinity, improvement in oil rate and stabilisation in water cut were obtained in the monitoring well and in one of the producers. Since injection was done through one well only improvements in terms of recovery could not be quantified. The aim was to gain field handing experience of such pilots as well as to assess field recovery potential of the process. On final analysis scheme has been considered as successful in terms of injection and production performance and has led to expansion of the process in the neighbouring areas of the pilot.

Introduction

Use of aqueous polymer solutions for improving reservoir sweep efficiency by controlling mobility of injected water has become an established practice in oil field operations. The process is more effective in case of a heterogeneous reservoir containing moderately viscous crude and has been successfully implemented in Sanand field situated in western part of India. Production from the field commenced in 1969 and primary recovery predicted on the basis of simulation studies was 14 % of IOIP. Considering wide variation in petro-physical properties of the reservoir and also the low primary recovery expected from the field, polymer flooding was thought to be the appropriate EOR process.

Injection of polymerised water in Sanand field on pilot scale through one well started in 1985. Performance analysis of the pilot indicated improvement in areal and vertical sweep of the reservoir and also enabled to rectify many problems encountered during field implementation of the process. Encouraging results obtained from the pilot and experience gained during field implementation led to expansion of the scheme in neighbouring areas. P. 549^
Coreflood Study of Surfactant-Alternating-Gas Foam Processes: Implications for Field Design
Authors: Kibodeaux K. R. , Rossen W. R.
Published: December 2007

The success of surfactant-alternating-gas (SAG) foam processes depends on foam behavior at very low liquid fractional flow fw-i.e., on whether and how foam breaks as it dries out during gas injection. It is difficult to conduct steady-state corefloods at extremely low fw, however. Therefore simulation studies of foam SAG processes rely on extrapolating steady-state data taken at much-higher values of fw Unfortunately, grossly different results are predicted depending on how these data are extrapolated.

This Berea coreflood study of SAG foam processes uses a unique coreflood apparatus in which both water saturation Sw and capillary pressure Pc are measured throughout the flood. Steady-state data were obtained to as low a value of fw as feasible, followed by continuous gas injection. Because Sw and pressure drop were measured during this period, the fractional-flow function could be extrapolated below the range in fw of the steady-state data.

During steady-state foam injection, for fw > 0.01, foam weakened and Sw fell as fw decreased. Foam was stable to a remarkably high value of capillary pressure. Between fw = 0.008 and 0.002, foam weakened sharply, and, remarkably, reimbibition occurred: Sw rose and Pc fell as fw decreased. This suggests that the fractional-flow curve for foam is not single-valued. Stated differently, there are at least two steady states, a "strong foam" and "weak foam" state, over a range of water saturations, and the behavior observed depends on injection history. This sudden foam collapse and reversion to the "weak foam" behavior under dry conditions mirrors the sudden jump to "strong foam" state reported in studies of foam generation. For lower fw, and during gas injection, Sw again declined as fw declined.

Implications of these results for field design of foam SAG processes are discussed. In particular, we illustrate how to extrapolate from a properly designed coreflood to field scale ID displacement using fractional-flow methods.
Well abandonment in the Los Angeles Basin: A Summary of Current Requirements, Practices and Problems
Authors: Evans B.L. , Sailor R.P. , Santiago E.
Published: December 2007

Well abandonment in the Los Angeles Basin: A Summary of Current Requirements, Practices and Problems.

Due to declining oil production increasing and real estate development, an increasing number of oil wells are being abandoned (or reabandoned) each year in the Los Angeles Basin. This paper summarizes the current requirements of the Department of Conservation's Division of Oil, Gas and Geothermal Resources (Division), the current abandonment practices of the industry and some of the difficulties encountered in properly abandoning or reabandoning wells. The paper has viewpoints from authors representing (1) the Division, (2) a major oil company with a large abandonment program, and (3) a consulting petroleum engineer engaged in reviewing wells and preparing abandonment programs.

This paper is considered to be particularly timely and important as the petroleum industry endeavors to leave oil fields in such a condition that surface development can safely follow.

Introduction

The Los Angeles Basin is one of the most prolific oil producing basins in the world. It contains over 60 oil fields where cumulative oil production exceeds 8 billion barrels.

Some of the major onshore fields and oil production are as follows:

Oil production in 1995 in the Los Angeles Basin totaled 38.6 million barrels (106,000 B/D) from 4,900 producing wells. At the end of 1995 there were 3,081 idle wells. Most of these wells are abandonment candidates. During 1995, 498 wells were abandoned in the Los Angeles Basin (Table 1). Since 1988, the rate of well abandonments has increased significantly (Fig. 1). This paper discusses the current regulatory requirements, practices and problem related to abandoning wells in the Los Angeles Basin.

A. Current Requirements

Since 1915, the Division has been charged with regulating the drilling, operation, maintenance and abandonment of all oil and gas wells in California, to prevent damage to life, health, property, and natural resources. Under Section 3106 of the Public Resources Code (PRC) the State Oil and Gas Supervisor has the authority to regulate the manner in which the Division's programs are carried out in the best interest of public safety and ultimate recovery of oil and gas.

In the early 1970's, additional safety concerns were raised by the Division regarding building in and near former oil producing areas. Although the oil and gas wells in these areas may have been abandoned properly in previous years, they may not be in conformance with today's more stringent abandonment regulations. The prevention or mitigation of methane gas migration from other sources into proposed or existing overlying structures also became an important matter for the Division; including, developers and building and fire inspectors.

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Stimulation for Methane Gas Recovery from Coal
Authors: Jeffrey R. G. , Wold M. B. , Choi S. K. , Settari A.
Published: December 2007

Over the past several years, a combination of data from field and laboratory experiments, published data from commercial treatments, and concurrent analysis and model development activities has led to a better understanding of the processes occurring in coal during stimulation operations. At the same time, better modeling capabilities have been developed. For example, a new hydraulic fracture design model that includes pressure-dependent non-linear leakoff, multiple interacting fractures, and failure in the coal near the fracture plane as a result of changes in effective stress, is being developed and is being used to study fracture propagation in coal. In addition, two- and three-dimensional discrete element and hybrid finite element models that couple the mechanical and multi-phase fluid response of the coal have been applied to analysing problems arising in cavity completion operations.

The paper compares data obtained from field trials in coal seams with model simulations and discusses implications for stimulation design and execution.
Field Evaluation of Wells Fractured in The North La Barge Field Using Continuous-Mix Gelled Oil
Authors: Maberry L. J. , Tanner K. V. , McConnell S. B. , Hinkel J. J.
Published: December 2007

The chemistry and field application of a continuous-mix gelled oil fluid are described. A brief history of oil gelation and phosphate ester chemistry is presented, followed by a discussion of new complexation chemistry. Field case studies are presented on 90 wells fractured in the Wyoming North La Barge field, from Aug. 1994 to Oct. 1996. Gelled oil fracturing treatments performed using prior art chemistry are compared to those performed using an enhanced complexation chemistry.
Integrated Reservoir Description From Seismic, Well Log, to Production Data
Authors: Yang An-Ping
Published: December 2007

The increasing need to improve production from developed oil and gas fields requires more detailed and more accurate reservoir description. Our answer is a multidisciplinary approach integrating geophysics, geology, geostatistics, and engineering. For a field with seismic data, well logs, and production data, an integrated reservoir model can be more accurate than the conventional approach of passing the model from geophysicists to geologists then to engineers.

In the development stage of a field, a geological model would have been built. The model would have been tested against production data. Now If we are going to build a more detailed model, the existing reservoir model is a valuable input. When dealing with seismic data, time permitting, known information of structure and stratigraphy may be used. When converting time data to depth, well data may be used together with seismic information to build a 3D velocity model. Geostatistics may be used with velocity logs and seismic data to build a more accurate and detailed velocity model. Without a reasonable velocity model for time depth conversion, it is difficult to integrate well data and seismic data. A lithology model or porosity model may be built with well data, structure information, and seismic attribute as soft data. Seismic attributes are calibrated to well data. Geostatistics provides a way to properly weight between well data and seismic data. The reservoir model may be compared or calibrated with production data. Then we may go back and modify the velocity model or horizon picks, or we may modify the conversion from seismic attribute to soft data used in the geostatistical gridding. By iteration, our reservoir model will become more accurate because it honors geophysical, geological, and engineering data. Common data links and tools like geostatistics make the integration easier.

Field applications show that an integrated iterative approach to detailed reservoir modeling can provide a better model and help optimize production.