bluuebunny/crossref_metadata_2025 huggingface dataset:
Experimental and Theoretical Investigations Into New Invert Emulsion Scale Squeeze Technology
Authors: Lawless T.A. , Smith R.N.
Published: December 2007

The potential to utilise invert emulsion technology (say, brine dispersed in kerosene) with the aqueous phase containing a scale inhibitor in solution is presented as an attractive alternative to conventional scale squeeze technology. Such new technology can combat current deficiencies associated with lost and deferred oil and deliver a stepped change to the whole process of scale control. It is important for squeeze operations, however, that the emulsion can be injected safely downhole and encouraged to "break" during shut-in, thus allowing the aqueous inhibitor to be released and contact the rock structure promoting effective retention. The "broken" oil phase maintains continuity between pore spaces and promotes rapid oil productivity to return, post-squeeze, as result of relative permeability effects. Economic benefits are identified and detailed considerations relating to the appropriate physico-chemical and environmental characteristics of target emulsions are presented. Experimental evaluation exercises on more than 50 specialist surfactants and formulations, obtained from major chemical companies have been undertaken and are reviewed.

Emulsifier chemistry selection, structural requirements and mechanism of (de)stabilisation are recorded to yield systems triggered to operate at 90 C. The impact of brine/oleic phase ratios, surfactant loading and method of manufacture are described in detail. Phase mapping techniques to elucidate controlled breakage, rheology and field fluids compatibility are recorded to quantify performance. Emulsion droplet size and distribution are key parameters influencing flow and (in) stability under practical scenarios, and optical microscopy investigations on systems as a function of time and temperature are presented. A move from largely monodisperse droplets, of circa 1 m, to an evolving size distribution, via coalescence is reviewed from an experimental and theoretical assessment.

P. 195
Enhancement of Liquid Flow Through a Porous Medium by Ultrasonic Radiation
Authors: Aarts A.C.T. , Ooms G. , Bil K.J. , Bot E.T.G.
Published: December 2007

A new method to enhance the oil production rate is irradiation of the near-wellbore region by an ultrasonic source. The limited success for the application of ultrasound in well stimulation to date, however, is due to the lack of understanding of the physical mechanisms between an acoustic wave field and a porous medium. In this paper the mechanism in which ultrasonic radiation deforms the walls of the pores in the shape of travelling transversal waves, is studied. A quantitative description of the mechanism indicates that these waves induce a net flow of the liquid inside the pores, identical to peristaltic transport. Numerical calculations show a damping effect of liquid compressibility and a strong influence of pore wall hardness and power output on the net flow rate induced.

The occurrence of a flow induced by ultrasound has been confirmed by laboratory experiments. In these experiments a water velocity of almost 1 cm/s through a rubber capillary of 0.15 mm radius could be induced by an ultrasonic source of frequency of 20 kHz. By a comparison between the trends observed in the experiments and the theoretically predicted trends, the role of the peristaltic transport mechanism in acoustic well stimulation is discussed.

P. 239
Hydrate Concept for Capturing Associated Gas
Authors: Gudmundsson J.S. , Andersson V. , Levik O.I. , Parlaktuna M.
Published: December 2007

Natural gas hydrate (NGH) technology is an attractive alternative to capture associated gas on FPSO's to solve the stranded and marginal gas problem in the oil industry. Based on estimates for land-based plants, the capital cost of hydrate technology is considerably lower than LNG, methanol and syncrude technologies. Offshore-based hydrate plants are also expected to be lower in costs. Crude/hydrate slurry processes are being developed for use on FPSO's. NGH technology is safe, environmentally friendly and easily scaleable.

P. 247
Using Optical Fluid Analysis To Evaluate Downhole Fluid Sample Contamination
Authors: Morris C.W. , Felling M.M. , Butsch R.J. , Sass W.
Published: December 2007

Wireline formation testers are commonly used to obtain fluid samples and measure formation pressure during openhole logging operations. The identification of the fluid usually depends on the analysis of the sample chamber contents at the surface. A new approach is now possible using the measurement of in-situ optical fluid density. This analysis can be used to determine the formation fluids and to evaluate significant fluid characteristics in real time.

The optical fluid analysis technique utilizes a visible and near-infrared absorption spectrometer for fluid discrimination and a refractometer for free gas. The spectrometer measures the transmittance of a liquid at 10 different wavelengths and distinguishes between oil and water by comparing the resulting absorption spectra in the visible and near-infrared region. The spectrometer yields quantitative data on fluid phase volumes and qualitative data concerning fluid coloration. Experiments were performed to catalog the optical fluid density characteristics of typical hydrocalbons, formation waters, filtrates, drilling mud systems, and mixtures of these fluids.

Utilizing this data base, optical density measurements can do an excellent job differentiating between oil and water. Hydrocarbon responses also show a strong correlation trend with optical fluid density measurements and can be used to estimate the in-situ oil gravity. Furthermore, differentiation between oil~base drilling fluid filtrates and hydrocarbons is possible. This outcome was observed with diesel, synthetic oil, and various other oil-base filtrates.

A new technique has been developed, which performs a weighted regression analysis on the optical spectrum, to quantify the mud filtrate contamination, water, and formation hydrocarbon in real-time. Field examples are presented to illustrate the application of the optical density information to the interpretation of formation fluid characteristics. The technique reduces overall sampling time, minimizes sample contamination, and improves sample quality.

P. 283
T2 Relaxation Time Versus Mercury Injection Capillary Pressure: Implications for NMR Logging and Reservoir Characterisation
Authors: Lowden Benjamin D. , Porter Matthew J. , Powrie Linda S.
Published: December 2007

A link between distributions of T2 relaxation time and capillary pressure curves has been demonstrated in several articles published over the last few years. Efforts to establish a link have mostly concentrated on high pressure air/mercury experiments (MICP). Establishing a link between T2 and MICP is important because it adds confidence to estimates of bound fluid, free fluid, and permeability from NMR logs. The link also provides another route to saturation height functions. However, experience working with NMR logs has shown that estimates of bound fluid are frequently under or overestimated and the default parameters used to determine bound fluid (e.g. T2 cutoffs) have to be adjusted to compensate for this. Often, little is known about how these adjustments relate to the actual pore system.

Analysis of 176 core samples representing a broad spectrum of sandstone reservoirs demonstrates the link between T2 and MlCP is unpredictable. This result challenges use of simplistic pore models for predicting bound fluid and explains why bound fluid estimates from NMR logs are often wrong. However, there is sufficient similarity between data sets for T2/Pc functions to be developed locally from core on a well-by-well basis. These functions can be applied to NMR logs using a process of pattern recognition which identifies similar NMR response type's within logs and core samples. NMR response types and their associated T2/Pc function provide information about upscaling and flow units.

P. 323
Multiple Fracture Stimulations In Horizontal Open-Hole Wells The Example of Well Boetersen Z9, Germany
Authors: Kamphuis H. , Aretz R. , Nitters G. , Loidl H.
Published: December 2007

The hydraulic fracturing of uncased wells or wells completed with a pre-drilled liner carries a risk of early proppant screenout. On the other hand, this can be a very cost-effective completion and stimulation method. This paper describes the successful application of multiple hydraulic fracturing in a deep horizontal gas well, Boetersen Z9, which was completed with a pre-drilled liner.

The first step in the design of the treatment was to determine the optimum positions of two propped fractures with information from a production log and from multifrac inflow simulations. Weakening the rock by perforating would raise the probability that two hydraulic fractures would he created at these positions during fracturing. The actual positions of the fractures were later estimated from the minifrac analysis. The main pumping treatment was an extension of common practice. Pump rates were maximized so several fractures could grow simultaneously to the planned length and width. A large stage with medium proppant loading was pumped to confirm access to the fractures before stages with higher proppant loadings were pumped. Precise stage volumes were inferred from the minifrac and took into account the uncertainty in the actual positions of the fractures. Resin-coated proppant was used throughout the job, rather than being used as a tail-in only, because fractures could become packed off at any time during the job and proppant flowback is avoided for each of them.

The well capacity increased from 7000 m3/h at 100 bar FWHP to 20000 m3/h at 370 bar. Skin and good communication between the fractures and the open-hole wellbore may have contributed to the success of the treatment.

P. 351
Effective Algorithm for Calculation of Minimum Miscibility Pressure
Authors: Jessen Kristian , Michelsen Michael L. , Stenby Erling H.
Published: December 2007

This paper describes a new algorithm developed for calculation of the minimum miscibility pressure (MMP) for the displacement of oil by a multicomponent injection gas. The algorithm is based on the key tie line identification approach initially studied by Wang and Orr. A new global formulation is introduced to describe and locate the sequence of nc- 1 key tie lines controlling the development of miscibility. In this new formulation, a number of numerical weaknesses of the original approach have been eliminated resulting in a robust and highly efficient algorithm. The computation time is reduced significantly and is clearly superior to other methods described in the literature. For a 15 component fluid description the MMP is determined within a few seconds on a PC. Hence the algorithm offers an efficient tool for projects where a large number of MMP calculations are needed (e.g. lumping and gas enrichment studies).

A case study is presented based on a real reservoir fluid for which PVT studies, swelling test and slimtube experiments have been performed. The study aims at investigating the influence of the characterization, tuning and lumping procedure used for generating a fluid description on the prediction of the MMP.

Based on the generated fluid description, a gas enrichment study is presented where the optimum mixture of two available injection gasses is determined aiming to optimize the gas injection project.

P. 559
Curvilinear Local Grid Refinement
Authors: Ghosh S.
Published: December 2007

A local orthogonal curvilinear coordinate system is used for Local Grid Refinement (LGR) of rectangular wellblocks in a finite difference grid. The refinement is hybrid since the curvilinear well-subgrids are approximately radial close to wells, while approximately rectilinear near wellblock boundaries. A composite of a local stretching and a conformal transformation is used to map individual wellblocks onto the unit disk on the complex plane. The pre-image of a radial grid on the complex plane becomes an orthogonal curvilinear grid on a k-isotropic real plane, centered at the well. The method allows us to avoid use of a numerical correlation for effective wellblock radius, and the associated limitations of the conventional Peaceman well model no longer apply.

Radial gridblock centers on the complex plane can be distributed logarithmically. This allows for an optimum spacing of gridblocks, and is a major advantage over Cartesian near-well LGR.

For the well-subgrids, curvilinear gridblock pore volumes are obtained by a numerically inexpensive integration on the complex plane. The details of the numerical methods that make pore volume determination rapid and viable for realistic field-scale simulations, will be presented elsewhere. Inter-block transmissibilities, half-boundary transmissibilities and well indices are obtained from an analytic potential for radial flow on the unit disk. This scheme is both more accurate and less cumbersome than those based on curvilinear grid geometry. Furthermore, the determination of gridblock centers on the real plane becomes unnecessary.

The hybrid nature of the well-subgrids reduces grid discretisation errors near wellblock boundaries. The method easily accommodates k-anisotropy and off-centered wells. For multi-phase problems, when near-well gridblocks become small the fully implicit solution technique is applied to the well-subgrids, while an implicit pressure, explicit mass (IMPEM) technique is applied to the parent coarse grid.

Owing to orthogonality, adding curvilinear LGR capability does not require extensive reprogramming of a five-point (on the plane) finite difference simulator. This is important from a practical standpoint. The present curvilinear LGR formulation has been integrated into a general purpose full-field finite difference simulator (with existing Cartesian LGR capability) without any reprogramming of the simulator kernel.

The method applies to well regions comprising several coarse gridblocks in the vicinity of wells, provided these well regions do not have areally varying k-anisotropy. Extensions to polygon well regions are also possible, making the method applicable to cornerpoint or general flexible grids. This enhancement is only outlined in this paper.

Several applications have been chosen to demonstrate the potential of curvilinear LGR. Comparisons are also made between curvilinear and Cartesian near-well LGR.

P. 29
Petroleum Reservoir Simulation Coupling Flow and Deformation
Authors: Cuisiat F. , Gutierrez M. , Lewis R.W. , Masters I.
Published: December 2007

The paper presents a discussion on the issues related to the interaction between rock deformation and multiphase fluid flow behaviour in hydrocarbon reservoir simulations. Pore pressure and temperature changes resulting from production and fluid injection induce rock deformations which should be accounted for in reservoir modelling. Reservoir rock deformation can affect the permeability and pore compressibility of the rock. In turn, the pore pressures will vary due to changes in the pore volume. The deformation of the surrounding non-reservoir rocks (under-, side- and over- burdens) should also be taken into account in order to assess their effects on the overall reservoir compressibility as well as the loads transmitted to the reservoir by the weight of the overburden.

The paper presents the formulation of Biot's equations for multi-phase fluid flow in deformable porous media. Based on this formulation, it is argued that rock deformation and multi- phase fluid flow are fully-coupled processes which should be accounted for simultaneously. However, the coupled equations can be decoupled to a classical hydraulic diffusivity equation for pre-defined simple stress paths. In the general case, by contrasting Biot's equations and its finite element discretization to the corresponding multiphase fluid flow equations used in classical reservoir simulations, it is shown that reservoir simulators neglect or simplify important geomechanical aspects that can have impact on reservoir productivity. This is attributed to the fact that the only rock mechanical parameter involved in reservoir simulations is the pore compressibility. This parameter is not sufficient in representing aspects of rock behaviour such as stress path dependency and dilatancy, which require a full constitutive relation. Furthermore, the pore pressure changes due to the applied loads from the non-pay rock cannot be accounted for by simply adjusting the pore compressibility. Example problems are shown in order to illustrate the importance of coupling flow and deformation in reservoir simulators.

P. 63
Brage Field, Lessons Learned After 5 Years of Production
Authors: Lien S.C. , Lie S.E. , Fjellbirkeland H. , Larsen S.V.
Published: December 2007

The Norwegian North Sea Brage field is currently on decline from its plateau oil rate of 19 400 std m3/d. This paper summarizes five years of production experience from the two highly different reservoirs that have been developed so far.

The fluvial, Lower Jurassic Statfjord formation consists of 1000 to 4000 md sandstone reservoir, with excellent vertical and lateral communication properties. A recovery of approximately 64% is expected from waterflooding the highly undersaturated 36 API oil.

The shallow marine Fensfjord formation, of Middle Jurassic Age, is a stratified sandstone reservoir with average zone permeabilities in the range of 1 to 200 md. Calcite layers and high permeability strikes, with up to 5000 md permeability, amplify the heterogeneity and complexity of this reservoir. The oil has similar properties as in Statfjord, but a recovery of only about 32% is expected. The principal recovery mechanism is aquifer support aided by water injection from the flanks.

The initial Fensfjord development was based on vertical wells with perforated cemented liner. Early production experience proved sand production to be a major problem. To avoid sand production, two wells were hydraulically fractured with proppants. This concept has later been left in favour of horizontal wells with sand screen, sliding sleeves and external casing packers (ECP's).

New water injection wells are horizontal. In these wells the horizontal section is divided into two parts: the toe part is completed with a sand screen and accessed through tubing; the heel part is a perforated liner and accessed through the annulus. In this way the two parts can be controlled as two individual injectors. An additional benefit is the possibility of producing oil from the toe part of the well while at the same time injecting in the annulus section.

A water-alternating-gas (WAG) injection pilot was established in the Fensfjord reservoir in 1994. Following a successful one-year pilot, with emphasize on performance monitoring through the use of tracers and mapping of high permeability streaks, the WAG process has been gradually expanded to include six injectors.

To avoid sulphate scale, injection of seawater has been replaced by injection of formation water produced from Tertiary sands in the shallow Utsira formation.

P. 103
A Techno-Economic Feasibility Study of Asphaltene Inhibition Squeeze Treatments
Authors: Lullo Alberto G. Di , Lockhart Thomas P. , Carniani Carlo , Tambini Mauro
Published: December 2007

Down-hole asphaltene deposition is an increasingly important issue for many oil fields and has stimulated interest in developing both remedial and prevention technologies. In previous work we have developed asphaltene solvents which optimize remedial treatments for the Villafortuna-Trecate field.

The work described here was aimed at assessing the possibility to achieve further cost reductions through adsorption squeeze treatments with an asphaltene deposition inhibitor. This objective is both economically and technically ambitious since squeeze treatments must compete with optimized solvent washes and because their success is based on the mutual interactions among additive, rock and produced fluids.

We have systematically studied the interplay between the technical and economic aspects of the intended treatment, with the purpose of identifying a priori the conditions giving rise to economically attractive treatments. This has been achieved by comparing the cost per year of the squeeze treatments, computed as a function of the relevant parameters (rock and inhibitor characteristics, well production, desired treatment life and job execution) through the application of a chemical adsorption squeeze simulator, with the annual costs of solvent washes. The acceptable asphaltene inhibitor "profile" thus obtained has turned out to be a powerful guide for laboratory experiments to select candidates for trial treatments.

The main conclusions are different for the case of high pressure reservoirs, for which the damage does not induce any decrease in production flow rate, and low-pressure reservoirs, for which the damage is associated with a production decrease over time.

For high-pressure reservoirs, high-productivity wells (> 300 m3/day) impose severe constraints on inhibitor performance, including activity at concentrations below 10 ppm and stringent adsorption/desorption behavior. For low-productivity wells (< 100 m3/day), instead, inhibitor activity at 50 ppm becomes acceptable, thus enlarging the class of products that are potential candidates for the intended application.

For low-pressure reservoirs, results depend on the fraction of production lost during asphaltene damage and on the capability of the additive to keep production constant during its period of activity. For high-production wells, the range of applicability of squeeze treatments may be significantly enlarged.

Example data are presented for the Eni – Agip Division Villafortuna-Trecate field, but the method employed is general and can be used to evaluate applicability to other fields.
Inflow Performance Relationships of Horizontal and Multibranched Wells in a Solution- Gas-Drive Reservoir
Authors: Retnanto Albertus , Economides Michael J.
Published: December 2007

In predicting and optimizing the performance of single and multiple wells, or complex well architecture, within a drainage or flow unit, we have favored benchmark analytical or semianalytical models. Recently, a general productivity model has been constructed and presented that allows for the performance prediction of any single- and multi-well configuration within any reservoir geometry in both isotropic and anisotropic media. Such an approximation is known to have limitations when applied to two-phase reservoir flow. This work used a numerical simulator to generate IPR's for horizontal or multibranched wells producing from a solution- gas-drive reservoir. First, a base case is considered with typical fluid, rock, and reservoir properties. Then, variations from the base case are investigated. These variations cover a wide range of fluid, reservoir, and well characteristics. The effects of numerous reservoir and fluid properties on the calculated curves are investigated. Bubblepoint pressure and reservoir depletion have a significant effect on the curves. A generalized dimensionless IPR based on nonlinear regression analysis of simulator results is developed. This IPR curve is then used to predict the performance of horiz'ontal and multibranched wells in a solution-gas-drive reservoir combined with our productivity model. For relatively low bubblepoint pressures, the curves coalesce on Vogel's classic relationship. For higher pressures they deviate substantially.

P. 255
Proposal for Certification Program for Petroleum Engineers
Authors: Arnold Charles W.
Published: December 2007

GOAL

The proposed Certification Program is a technical-professional recognition program to enhance the professional stature and welfare of petroleum engineers. The objectives of the program are:to encourage and reflect the continuing updating of skills by petroleum engineers;to identify and discern the clearly competent professional;to foster continuing recognition of the competent petroleum engineer in his professional career; andto aid the advancement of the technical and scientific disciplines associated with the profession.

CERTIFICATION AND REGISTRATION

The proposed Certification Program compliments and supplements professional registration programs. Registration means legal professional registration programs. Registration means legal license to practice in a particular geographical area; certification means recognition of an individual's continuing technical competence to engage in professional practice.

In areas where no registration laws exist to cover work by petroleum engineers, the Certification Program sponsored by the Society of Petroleum Engineers could provide a form of recognition of competency Petroleum Engineers could provide a form of recognition of competency in petroleum engineering principles and practices.

ELIGIBILITY

To gain certification under the SPE-sponsored program, the applicant must meet the following requirements:Experience: A minimum of six years' experience in an engineering capacity related to the petroleum industry, preferably in the exploration, drilling, production, or pipelining areas. Such experience can include positions in industry, government, or in teaching at a four-year college or university. Credit of one year for a Masters degree and two years for a Doctorate degree will be provided.Registration: A current license as a Registered Professional Engineer in the state in which he practices.Education: (Applies only for those petroleum engineers who, for reason of residency, are unable to qualify for engineering registration at the time of application for certification.) A degree in engineering, engineering science, or applied science from a college or university whose engineering or scientific curricula is approved by the Engineers Council for Professional Development (ECPD) or the SPE Board of Directors.
Maximizing Production From Gravel Packed Wells at Gullfaks Field by Stimulation and Installation of Multiphase Booster Pumps
Authors: Andersen K.I.
Published: December 2007

The Tarbert and Ness formations in Gullfaks are poorly consolidated with high porosity and productivity. Mound 50 cased hole gravel packs have been installed to date, most of which have performed well with regard to sand control.

Data obtained from permanent downhole pressure gauges show a significanfly lower Productivity Index in the gravel packed wells compared to conventionally perforated producers. At increasing drawdown and watercuts, wells with PI less than 100 Sm3/D/bar (40 BBL/psi) become rate limited by the 65 bar (1000 psi) separator pressure at Gullfaks.

Maintaining and improving production from the individual gravel packed wells must therefore be done by stimulation or by artificially reducing backpressure against the wellhead.

Chemical treatments to remove near-wellbore damage have been effective in several cases, yielding a temporary or permanent increase in productivity and oilrate. Calcium carbonate scale can be efficiently removed by bullheading 5 % HCl. Wells which do not respond to acid or have risk of increased watercut can be mechanically stimulated by reperforating the gravel pack. This will generally induce a sand limitation.

In 1994, a pilot multiphase pump unit was installed at the Gullfaks A platform to gain operating experience with the technology and improve production from two of the gravelpacked wells. The pump has proved capable of increasing production from the A-28 well by 300 Sm3/D (1800 BOPD) and has extended the lifetime of the 1000 Sm3/D A-5H well by one year.

Based on the positive results of the pilot programme, 3 new multiphase pump units of higher capacity will be installed topside Gullfaks A and Gullfaks B during 1998/99. This system will be capable of boosting a total of nine wells from 45 bar manifold pressure up to the required 65 bar separator inlet pressure.

P. 439
Safe Removal and Disposal of Naturally Occurring Radioactive Materials from Oilfield Equipment
Authors: Janssen R. J. J. N. , van der Last B.
Published: December 2007

Most natural raw materials contain small traces of radionuclides from the uranium and thorium decay series. They are widely known as Natural Occurring Radioactive Materials (NORM). Depending on production or processing parameters these materials can be deposited as a scale on the internal surfaces of production or processing installations.

Installation parts contaminated with NORM have to be decontaminated before they can be disposed of, either by "wet" technologies or "dry" technologies. "Dry" technologies offer the advantage of (almost) zero secondary radioactive waste generation. For this reason a range of "dry" technologies is made available at our facility.

For tubing a dedicated tool is used: a self-propelling mechanical grinder. For other installation parts manual mechanical technologies are used which enable full decontamination even in less accessible corners.

This paper will also highlight associated topics like release measurements and health & safety.
Simulation of Paraffin and Asphaltene Deposition in Porous Media
Authors: Shaojun Wang , Civan Faruk , Strycker Arden R.
Published: December 2007

A one-dimensional, three-phase and four-pseudo-component model for simultaneous deposition of paraffin and asphaltene in porous media is developed and validated by experimental data. The paraffin and asphaltene retention by static and dynamic pore surface depositions, and pore throat plugging is considered. A fully implicit finite-difference numerical scheme is developed and solved by a double iteration procedure. The simulator is applied to six typical cases of the reported laboratory core tests. The model accurately predicts the results of the laboratory core tests within the order of the accuracy of the laboratory measurements. The case studies reveal that the static surface deposition may occur in certain situations even without the fluid flowing. However, during flow, the dynamic surface deposition is predominant. The plugging deposition may occur under certain conditions, depending on the properties of the fluid, the porous media, and the paraffin and asphaltene precipitates, and the injection rate and pressure conditions. The best estimates of the model parameters are determined by history matching. These studies indicate that the approach taken to model and simulate the simultaneous paraffin and asphaltene deposition during the flow of oil through porous media is adequate.
Modeling of Profile Modification by Induced Precipitation
Authors: Shu Zhengying , Roegiers Jean-Claude
Published: December 2007

This paper presents a comprehensive two-phase, multi-species mathematical model for selective plugging of highly watered-out zones by induced precipitation. The approach considers the porous medium as having two regions (macropores and micropores) with different permeabilities. Two sets of coupled equations, one set for each region, are derived to simulate the selective plugging processes occurring in the formation. The mechanisms causing alteration of porosity and permeability include particles mobilization and retention in pore spaces, particles transfer at fluid-fluid interfaces, as well as chemical and physical precipitations. The ternary phase diagram is applied to represent the phase behavior during flow and plugging processes. The model allows changes of temperature both in fluids and rock. The effects of concentration, temperature, and pressure on density, viscosity, porosity and permeability are also considered.

The capability and validity of the model are demonstrated by comparing its predictions with experimental data from alcohol-induced precipitation, a newly proposed selective plugging method. Simulation results from the model are shown to be in good agreement with experimental measurements. This model can be used for diagnosis, evaluation, and simulation of selective plugging processes caused by induced precipitation in both laboratory tests and field operations.
A Study of Refracturing in Low Permeability Reservoirs
Authors: Wang Fengjing , Ding Yunhong , Lu Yong
Published: December 2007

Several key problems concerning refracturing in low permeability reservoirs have been studied, i.e. effectiveness of initial fractures, effects of water cut, reservoir pressure on post refrac performance and selection of candidate wells, optimization of fracture length, treatment design, implementation and evaluation. Both technological and economic achievements have been obtained.

P. 333
Effects of Important Factors on Alkali/Surfactant/Polymer Flooding
Authors: Yuan Shiyi , Yang Hua , Shen Kuiyou , Yang Puhua
Published: December 2007

Based on the research of earlier stage, a detailed investigation was conducted over the synergistic oil displacement mechanism and various physico-chemical phenomena. Especially, the new physico-chemical phenomena of combination flooding recognized in recent years have been further studied and described in detail. Both the mathematical model and the software ASP used for combination flooding established before have been systematically improved or modified. For the first time, such factors as change of interface tension caused by the multi-extraction of alkali, change of solution viscosity due to the further polymer hydrolysis after adding alkali, and change of combination system interface tension by adding polymer have been incorporated into the mathematical model. Thus the model is a more consummate, more exquisitely described and more realistic one. Based on the detailed analysis of various vital influential factors, the improved simulator ASP is used to conduct a great number of series of numerical simulation research. A systematic analysis is firstly carried out upon the sensitivity of various influential factors (including geological factors, physicochemical phenomena, starting conditions and operational parameters) of combination flooding and its effects, from which important recognitions and conclusions in regular have been drawn. A further understanding has been achieved on combination flooding process that is important for further researches and oilfield applications.

P. 357
In-Door Study of Hydrocarbon Miscible Flooding Cases
Authors: Shen Pingping , Shi Wen
Published: December 2007

From the beginning of 90's, volatile reservoirs have been frequently discovered in Western China. Systematic hydrocarbon miscible indoor studies were performed when drawing the development program of the reservoirs. The studies include physical experiments and EOS compositional modeling in 1D, 2D and 3D of miscible, near-miscible, immiscible and WAG drives. The paper summarizes main achievements of the studies on hydrocarbon miscible flooding and the recommended work flow path completed by the Research Institute of Petroleum Exploration and Development (RIPED). Some new understandings on hydrocarbon miscible mechanisms are also discussed.

P. 375
Study on Reservoir Engineering: ASP Flooding Pilot Test in Karamay Oilfield
Authors: Gu Hongjun , Yang Ruiqi , Guo Shuanggeng , Guan Weidong , Yue Xinjian , Pan Qianyin
Published: December 2007

In the northern part of Erzhong District in Karamay conglomerate oilfield, Xinjiang, China, ASP pilot tests have been conducted in 13 wells in a pilot area of 0.031 square kilometers since September 1994. The pilot area was developed through combining laboratory results in recent years with specific conditions in the field. This test is aimed to verify oil displacement efficiency of ASP and related reservoir behaviors, to improve production techniques necessary to obtain remaining oil from conglomerate reservoirs, and to provide data for economic feasibility evaluation.

P. 385
Some Problems in the Exploration and Exploitation Low Permeability of Oil and Gas Resources in China
Authors: Luo PingYa , Meng YingFeng , Shu ShiHong
Published: December 2007

In China, at least 50% of the total oil and gas resources exist in the low permeability resrevoirs. Whether the low permeability oil and gas resources can be produced and utilized commercially is one of the important problems for China's energy supplying in the 21st century. The most important problem in the exploration and exploitation of low permeability oil gas resources is the serious formation damage in pay zones. This formation damage exists from the beginning to the end in drilling, well completion, stimulation, oil and gas production. Another important problem is the economical benefit. The production and utilization of low permeability oil and gas resources was limited by the high input and the low output. Based on systematical analysis of reservoir characters, damage mechanism and flowing patterns of low permeability reservoirs, a suit of techniques was worked out to deal with low permeability reservoirs in this paper, including exploration, reservoir description, drilling, well pattern, stimulation and production.

P. 429
A Super-Dual-Porosity Simulation Model for Water-Channeling in Naturally Fractured Gas & Oil Reservoirs
Authors: Zhou Hongbo , Li Zhipin , Li Yun
Published: December 2007

The dual porosity model, since it was put forward, has been regarded as the best simulation model in describing the fluid flow through naturally fractured heterogeneous reservoirs. Nowadays it has been extensively applied to the development of gas & oil fields. In most gas fields in Sichuan, China, the distribution of natural fractures and aquifers is complicated. And this type of fractured systems could usually experience some abnormal flow phenomena such as that the crestal well produces water while the downdip well in the same gas reservoir produces gas; or the same gas well produces water intermittently; It is difficult to explain these phenomena by existing principles. All kinds of conventional dual-porosity models, which are based on the ideas proposed by Warran & Root in 1963, cannot simulate satisfactorily such problems in practice. Therefore, these problems often puzzle the people involved in the development of gas & oil fields. In this paper a super-dual-porosity model is presented for the serious water-channeling phenomena in the fractured reservoirs, especially the gas reservoirs in Sichuan, China. A new mathematical model is developed by introducing larger-aperture fractures and a new combined-fracture media, and is used to describe quantitatively the fluid-channeling through the larger-aperture fractures. Then the solution and coding work of this model are also completed. Finally, the results calculated by the new model are compared with those obtained by running the conventional models. The practical applications demonstrate that if the larger-aperture fractures are known this model could make a good history match and dynamic prediction, and it is very difficult for the conventional models to perform the tasks as well.

P. 467
Enhanced SPE Involvement in Education: The Education Coordinating Committee
Authors: Lee W. J.
Published: December 2007

In early 1998, the SPE Board established an Education Coordinating Committee charged broadly with oversight of the society's compliance with Board-approved policies on educational matters. This action was the result of the need expressed by industrial and academic delegates to the 1997 SPE Colloquium on Petroleum Engineering Education.
Policies Necessary For The Conversion Of Utility Power Plants To Coal Fired Facilities
Authors: Smith Don S.
Published: December 2007

Smith, Don S., Commissioner, Federal Power Commission

Introduction

Electric utilities in the United States use in the generation of electricity more than one-quarter of all the primary energy consumed in this country by all segments of the economy. To date, although nuclear energy is making rapid inroads into the generation field, fossil fuels - coal, oil, and gas - remain the principal source of energy, and it appears that fossil fuels will continue to play a major role in the electric power generation picture until the turn of the power generation picture until the turn of the century.

In 1973, 55 percent of the fossil energy used by electric utilities (on a B.T.U. basis) was derived from coal, 21.6 percent from oil, and 23.4 percent from gas. However, two significant elements in our fuel supply picture which have clearly emerged in recent years are apt to change this electric utility fuel mix. One element is the growing scarcity of natural gas and the need to conserve gas for higher priority uses than under electric utility boilers; the second is our determination to reduce our national dependence on foreign sources of oil supply. Since this country is well endowed with coal reserves, the obvious substitute fuel for scarce gas and foreign oil is coal. A variety of physical and institutional obstacles, however, stand in the way to more rapid introduction of coal into our energy economy. It is my intention here to explore in greater detail the rationale for the need to convert more utility plants to the use of coal, to examine the obstacles to the greater use of coal in electric power generation, and to recommend policies which, I believe, are necessary for the conversion of utility power plants to coal-fired facilities.

1. FUELS FOR ELECTRIC POWER GENERATION

A. Historical Data and Projections of Electric Energy for Load

1) Historical Review. In 1920, thermal and hydro-electric power plants in the United States generated 39.4 billion kilowatt-hours of electricity; by 1970, generation had increased nearly 40-fold to 1,531.6 kilowatt-hours. During the past five decades, the average annual compound past five decades, the average annual compound rate of growth was 7.4 percent, i.e., electricity generation more than doubled each decade.
Pressure-Enhanced Penetration with Shaped-Charge Perforators
Authors: Glenn Lewis A.
Published: December 2007

Computational analysis demonstrates that the penetration of a shaped charge jet can be enhanced by at least 25% by imploding the liner in a high pressure light gas atmosphere. The gas pressure helps confine the jet on the axis of penetration in the latter stages of formation. A light gas, such as helium or hydrogen, is required in order to keep the gas density low enough so as not to inhibit liner collapse.
Low Gel Loading Increases Well Production in Eastern U.S.
Authors: Terracina J. M. , Yaritz J. G. , Powell R. J. , McCabe M. A. , Slabaugh B. F. , McKeon M. J.
Published: December 2007

This paper presents case histories showing that operators drilling in eastern states have increased oil and gas production by reducing the amount of guar polymer used to stimulate a well. The fluid system used in the 80 to 140°F applications in the region is a 20- to 25-lbm/Mgal guar with a buffered borate crosslinker that provides an instant crosslink. The wells being treated as described are shallow, and rapid complexation is needed to ensure proppant transport through the perforations.

Laboratory test results are also presented. Rheology and sand transport for the optimized fluid system are compared to similar properties of conventional borate-crosslinked fluids. In general, fluid properties of the low-guar polymer compare to properties of conventional borate-crosslinked fluids containing polymer concentrations 5 to 15 lbm/Mgal greater. Viscosity and fluid-efficiency values of the low-guar system (25 lbm/Mgal) compare to a 35-lbm/Mgal conventional borate-crosslinked fluid. Because reservoir cleanup after fracturing is an important component of production, production increases seen in these wells are mainly attributed to the lower gel loading used.
Key Parameters Controlling the Performance of Neuro-Simulation Applications in Field Development
Authors: Doraisamy H. , Ertekin T. , Grader A. S.
Published: December 2007

This paper describes the use of artificial neural networks in exploring field development strategies in conjunction with various recovery schemes. In reservoir engineering applications, the field development process is considered to be highly challenging due to inherent time constraints, lack of sufficient data, and the presence of several degrees of freedom that need to be taken into consideration. In this paper, the respective roles of the important neural network parameters with relevance to recovery scenarios under consideration are examined. The overall objective, in these recovery scenarios, is to increase the rate of oil recovery under specified GOR and WOR constraints. The increase in the oil recovery rate can be achieved by implementing an infill-drilling program or by introducing an improved recovery technique such as water or gas injection. In both cases, one of the critical decisions is to determine the locations of the new wells that need to be drilled.

This paper investigates the potential use of artificial neural networks as an effective tool in identifying the optimum well locations in field development studies for various recovery schemes. The efficiency and accuracy of an artificial neural network are controlled by various parameters that are specific to a given network topology. Two of the artificial neural network parameters that control the robustness of the entire process include the learning constant, and the number of middle layer neurons. Another issue that needs to be addressed is the hidden danger stemming from the over-training of a neural network. Over-training a neural network causes the network to memorize rather than learn. A training session that concludes with memorization rather than learning will cause the artificial neural network to generate biased answers during the prediction phase. Suggestions are made in this paper to avoid the occurrence of memorization during the training process. By developing a good understanding of the roles of these key artificial neural network parameters, one will be better equipped to successfully implement the proposed hybrid (soft and hard) computing methodologies to field development studies.
Federal Safety Standards For Gas Pipelines (A Guide For Industry)
Authors: Thomas J.C.
Published: December 2007

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

Introduction

Purpose Purpose The purpose of this guide is to assist the regulated industry in achieving a satisfactory level of safety through a better understanding of the meaning and intent of the minimum Federal Safety Standards.

Need for the Study

Gas pipeline operators face many challenges in their day-today activities. One area where a good strategy can help the operator allocate his resources purposefully is in the application of pipeline safety.

Method and Scope of Investigation

The information for this study was obtained from available literature and through personal pipeline safety experience. personal pipeline safety experience. The scope of this investigation is limited to those considerations that would be of interest to gas pipeline operators. These facts are discussed under the following three headings:Federal Safety Standards as minimum requirements,operator's responsibility in pipeline safety, andplanning for safety in system operations.

planning for safety in system operations.

DISCUSSION

Federal Safety Standards as Minimum Requirements

The Federal Safety Standards (FSS) for gas pipelines establish minimum regulatory requirements for designing, constructing, testing, operating and maintaining gas pipeline systems. The operator determines pipeline systems. The operator determines the methods and procedures for achieving safety and the Office of Pipeline Safety (OPS) of the Department of Transportation monitors the industry's performance.

Protecting the Public Protecting the Public The key to pipeline safety lies in Congress's intent of the Natural Gas Pipeline Safety Act of 1968. The Act intended the promulgation of rules and regulations for the promulgation of rules and regulations for the protection of the public and any conflict protection of the public and any conflict between the regulated industry and the regulators is resolved in the public interest.

Two-Party Understanding. The gas pipeline industry recognizes the need for pipeline industry recognizes the need for safety regulation.