bluuebunny/crossref_metadata_2025 huggingface dataset:
Sonic While Drilling: Have You Thought About Cuttings?
Authors: Marsala A. F. , Zausa Fabrizio , Martera Mauro Della , Santarelli F. J.
Published: December 2007

Sonic while drilling has long been considered a major goal by the industry because of its potential applications: real-time determination of pore pressure and overburden gradients, improved lithology change determination, seismic calibration, and detection of seismic reflectors ahead of the bit. Until now, only two methods were available to perform sonic measurements while drilling—the use of continuous coring or a specific measurement while drilling (MWD) tool. Unfortunately, both methods remain very expensive and suffer from technical limitations. A new technology [named pulsed ultrasound on cuttings (PUC)] has been developed to measure both compressional and shear-wave velocities directly on cuttings with dimensions as low as 1 mm. Laboratory and field implementations of the method are presented along with its validation against reference measurements.
NMR Imaging of Immiscible Displacements in Porous Media
Authors: Majors Paul , Li Ping , Peters Ekwere
Published: December 2007

We introduce a rapid, quantitative nuclear magnetic resonance imaging (NMRI) technique to resolve and measure multiple fluid phases in porous media. Liquids are resolved on the basis of their NMR spin-spin (T2) relaxation times, and their intensities are corrected by attenuation analysis. The phase-resolved and corrected NMRI intensities are normalized to yield fluid saturations. We present the procedure and limitations of this technique.

We present in-situ saturation measurements for three immiscible (oil and water) displacements in the same Berea sandstone core. We compared NMRI and effluent recovery methods. T2 of the displacement fluids were sensitive to displacement conditions.
Improved Technique for Stochastic Interpolation of Reservoir Properties
Authors: Painter Scott , Paterson Lincoln , Boult Peter
Published: December 2007

Stochastic interpolation methods for generating input for reservoir simulations require accurate models for spatial variability. New models based on fractional Lévy motion, a generalization of fractional Brownian motion, have strong empirical support. Stochastic interpolations based on the Lévy model have a higher degree of spatial variability compared to Gaussian fractals. In two-dimensional waterflood simulations, the breakthrough curves for the Lévy interpolation method are better clustered around predicted production behavior based directly on outcrop data.
Pitfalls in Pressure-Gauge Performance
Authors: Kikani Jitendra , Fair P. S. , Hite R. H.
Published: December 2007

Often, pressure-gauge systems for surface read-out (SRO) wireline work or for permanent installations do not perform according to their specifications; i.e., the pressure resolution obtained is lower than the gauge-design values. This seems natural because the borehole environment is nastier than the quiescence of laboratory calibration set up. Nevertheless, it is difficult to attribute the loss of resolution to a single problem.

This paper introduces the functional components of the pressure-gauge system where loss of resolution may occur. Specifically, it addresses cable-related problems, crossover, signal transmission, signal processing, time stamping, and temperature compensation. We show determination of pressure resolution from a processed signal by means of example calculations. The role of transducer specifications on overall data quality is addressed; i.e., what causes a 0.01-psi-rated transducer to yield a signal of only 0.75 psi quality? Field data from Tahoe and Bullwinkle prospects are used to illustrate some of the gauge-related problems and the solutions being proposed by the industry to overcome some of them.
An Experimental and Numerical Study of In-Situ Steamdrive During Cyclic Steaming
Authors: Dehghani Kaveh , Kumar Mridul , deZabala E. F. , Meyer R. F. , Duran Henry
Published: December 2007

A series of laboratory tests was conducted to investigate the in-situ steamdrive process and its effects on fluid displacement in porous media. The experiments show that in-situ hot-water flash may recover up to 60% of moveable oil and that the residual oil saturation after flash increases with lower initial water saturations. Conventional simulation with external-drive relative permeabilities led to under-prediction of oil recovery.
Auger Well Completions: Sand Control Installation and Mechanical Design
Authors: Norton S. J. , Smith C. D.
Published: December 2007

Nine producing wells have been completed on the Auger tension leg platform (TLP). The results have been better than anticipated, with average production-rate capability exceeding 11,000 BOPD and 25 MMcf/D gas per well. Completing wells from a TLP in 2,860 ft of water posed several unique challenges from an equipment as well as an operational standpoint. This paper discusses the completion operations from gravel packing through tree stack-up, noting the original plans and changes that were made during the program. Special procedures for perforating, stimulating, and gravel packing, special equipment requirements, and material selection are discussed.
Two-Phase Gas-Condensate Flow in Pipeline Open-Network Systems
Authors: Martinez A. F. F. , Adewumi M. A.
Published: December 2007

Even if gas transmission occurs after the necessary processing of the gas has been completed, condensation still occurs in the natural gas transmission and/or distribution systems. The quantity of the condensate formed will not only depend on composition, pressure, and temperature, but also on the unequal splitting phenomenon that takes place at T-junctions in a network system. This paper investigates the splitting phenomenon in horizontal-branching T-junctions. The compositional hydrodynamic model developed at Pennsylvania State U. is used to evaluate gas-condensate flow in a pipeline under steady-state conditions. Using a double-stream model for splitting analysis at T-junctions, the mass-liquid-intake fractions are determined. The junction is considered as a separator and the new compositions are calculated at the run and at the branch of the junction. Although quantitative validation of the model is limited by the incompleteness of the available data, a reasonable qualitative match of experimental data is achieved. The results demonstrate the predictive capability of liquid route preference in two-phase natural-gas/condensate flow at T-junctions. In addition to liquid split, compositional split is tested using polychlorinated biphenyl (PCB) as the focal point. It is found that the concentration of PCB is distributed in direct proportion to the liquid preference route, and the PCB concentration in the delivery points can be higher or lower than the inlet concentration at the supply point.
The Relation Among Porosity, Permeability, and Specific Surface of Chalk From the Gorm Field, Danish North Sea
Authors: Mortensen Jeanette , Engstrøm Finn , Lind Ida
Published: December 2007

The origin of the difference in the relationship between permeability and porosity for Danian and Maastrichtian chalk from the Gorm field offshore Denmark has been investigated. The investigation was based on 300 sets of core data (He-expansion porosity and air permeability) from Well Gorm N-22X. On 24 of the core plugs, the specific surface was determined by BET and, on 14 of these samples, image analysis was made.

The data were rationalized by the use of the Kozeny equation and it was found that each geologic unit had a characteristic relationship among porosity, permeability, and specific surface. Furthermore, it was found that the nature of porosity (intrafossil, intergranular, etc.) had no significant influence on the air permeability, so that the permeability of the chalk can be calculated from total porosity and specific surface.

Kozeny's empirical constant, c, was determined analytically from a simple porosity model and Poiseuille's law.
Downhole Measurements of Synthetic-Based Drilling Fluid in an Offshore Well Quantify Dynamic Pressure and Temperature Distributions
Authors: White W. W. , Zamora Mario , Svoboda C. F.
Published: December 2007

Accurate downhole and surface measurements of a synthetic-based drilling fluid were taken in a Gulf of Mexico well to resolve variances between actual and calculated pump pressures and to quantify equivalent circulating densities. Current American Petroleum Inst. (API) equations seriously underestimated drillstring losses, which accounted for the pump-pressure differences. Conversely, annular losses were much lower than predicted.
Waterflooding of Gas-Condensate Reservoirs
Authors: Fishlock T. P. , Probert C. J.
Published: December 2007

Gas-condensate reservoirs are usually produced by primary depletion. This technique is normally an efficient means of producing the gaseous hydrocarbon components but can be very inefficient in producing the more valuable liquid components that are left in the reservoir in a condensed liquid phase (oil). The recovery efficiency of the liquid components decreases with increasing richness of the gas condensate, making for a large improved oil recovery (IOR) target in some reservoirs. The usual approach to improving liquid recovery is to recycle produced gas through the reservoir. However, this technique may not be economically attractive when there is the possibility of immediate gas sales because of the discounting applied to the gas value when sales are delayed. An alternative means of improving liquid recovery is to keep the reservoir pressure above the dewpoint for a period by injecting water. Depending on reservoir characteristics, water injection may be continued throughout field life or the reservoir may be pressure depleted after a period of injection. Special relative permeability data, describing the mobilization of waterflood trapped gas by expansion, are necessary for the latter case.

This paper reports a simulation study that quantifies the potential benefits of the waterflood technique by use of simple reservoir models. For a fluid with a condensate to gas ratio (CGR) of 180 STB/ MMscf, total hydrocarbon recovery was optimized by injecting 0.25 hydrocarbon PV of water before pressure depletion. This increased the recovery efficiency of both the liquid and gaseous components, raising the total hydrocarbon recovery by 10% of the hydrocarbon mass initially present in the reservoir. For a richer, near-critical fluid with a CGR of 300 STB/MMscf, continued water injection gave the optimum total recovery, which was 21% of initial mass higher than for primary depletion. This improvement was achieved by greatly increasing the liquids recovery at the expense of a smaller reduction in the gas recovery. The results of this paper suggest that waterflooding of gas-condensate reservoirs might be a valuable IOR technique.
A Statistical Approach to Infill-Drilling Studies: Case History of the Ozona Canyon Sands
Authors: Cipolla C. L. , Wood M. C.
Published: December 2007

This paper details the application of limited single-well reservoir modeling to predict infill-drilling potential in tight gas fields. Distributions of ultimate recovery and drainage area were developed from a small sample set to estimate incremental reserves. A case history from the Ozona gas field, Crockett County, TX, illustrates this technique. Fifty-one wells were randomly selected from more than 1,500 producing wells to estimate the potential of 40-acre infill drilling. The distributions of production characteristics from the modeled wells reproduced those of the "full field." Calculated drainage areas ranged from less than 10 acres to more than 320 acres, with a median drainage area of 36 acres. Approximately 75% of Ozona Canyon wells drain less than 80 acres (current spacing), with 52% draining less than 40 acres. The statistical drainage area and estimated ultimate recovery (EUR) data were combined to estimate the potential reserve growth with 40-acre development. Approximately 1,125 locations, adding 400 Bcf of incremental reserves were identified. The average EUR for 40-acre infill wells is 353 MMcf of gas.
Tip Screenout Fracturing of Gas Wells
Authors: Fan Yong , Llave F. M.
Published: December 2007

Tip screenout fracturing, also known as frac&pack, has gained increasing prominence for well completion of unconsolidated and medium-high permeability formations. Oil wells with permeabilities up to 1,000 md have been treated using this technology. It is easy to postulate that gas wells with permeabilities of 50 md or higher can also be effectively frac&packed. This paper presents a model that describes the transient flow of polymer solution through a filter cake and the reservoir as a means to account for leakoff behavior during tip screenout fracturing of gas wells. The leakoff rate into the formation is determined by the pressure profile established during the treatment as a function of the properties of the fracturing fluid and the reservoir formation. Consequently, no constant bulk property (such as the leakoff coefficient) is used in the fracturing model. This paper shows how to terminate the fracture growth at the appropriate time, and how to design frac&pack treatments resulting in fracture widths several times larger than those from traditional fracturing.
The Impact of Integrating Static and Dynamic Data in Quantifying Uncertainties in the Future Prediction of Multiphase Systems
Authors: Huang Xuri , Gajraj Allyson , Kelkar Mohan
Published: December 2007

This work presents a qualitative analysis of the uncertainties in performance prediction for a reservoir characterization process in which static and dynamic data are combined. Using primary, single-phase production data as the dynamic constraint in the inversion, we evaluate the quality of the models when they are used in alternative or subsequent production scenarios. We conclude that, provided the well configuration remains the same as that used for the dynamic constraint in the inversion, the models perform well when the production stage remains single-phase, primary depletion, even at the individual well level and for future prediction. For multiphase primary production, there is also a reasonable match in performance, although not as good as for a single-phase case. This is because such depletion processes are controlled by the permeability in the near-wellbore region, which is adequately reconstituted by the characterization process used; we observed, however, that the multiphase density variations with time had little impact. However, the fine scale, inter-well permeability patterns of the different realizations obtained by the integration of the dynamic and static data are not sufficiently resolved and so are unable to capture adequately the inter-well permeability heterogeneity patterns that are necessary for accurate waterflood performance matching. Thus, the models produced by inversion in which primary recovery data are used as a constraint are inadequate in predicting the performance of processes involving injection.
An Expandable-Slotted-Tubing, Fiber-Cement Wellbore-Lining System
Authors: Stewart R. B. , Gill D. S. , Lohbeck W. C. M. , Baaijens M. N.
Published: December 2007

An expandable-slotted-tubing, fiber-cement wellbore-lining system has been developed. Its purpose is to temporarily secure the integrity of a wellbore section to allow drilling operations to continue through deeper overpressured or depleted zones. The lining is installed below the previous casing with no or minimal reduction in hole diameter.

The technology makes it possible to realize major reductions in well costs by avoiding the use of certain intermediate and contingency casing strings. It also helps in high-pressure/high-temperature (HPHT) well designs where the requirement for additional casing strings may become excessive.

The paper outlines the technologies involved and installation/ evaluation procedures. Details are given of onshore and offshore field trials in Europe and the U.S.
A Study of Oil/Water Flow Patterns in Horizontal Pipes
Authors: Trallero J. L. , Sarica Cem , Brill J. P.
Published: December 2007

Oil/water flow-pattern transitions in horizontal pipes have been studied botd experimentally and tdeoretically. A new state-of-tde-art oil/water test facility was designed, constructed, and operated. A transparent test section (5.013-cm inside diameter × 15.54 m long) can be inclined at any angle, to study botd upward and downward flow simultaneously. Mineral oil and water were tde working fluids (µo/µw= 29.6, ρolρw= 0.85, and σ = 36 dynes/cm at 25.6°C).

A new classification for oil/water flow patterns based on published and acquired data is proposed. Six flow patterns were identified and classified into two categories: segregated flow and dispersed flow. Stratified flow and stratified flow witd some mixing at tde interface (ST&MI) are segregated flow patterns. tde dispersed flow can be eitder water dominated or oil dominated. A dispersion of oil in water over a water layer and an emulsion of oil in water are water-dominated flow patterns. An emulsion of water in oil and a dual dispersion are oil-dominant flow patterns.

The oil/water flow-pattern transitions for light oils are predicted using tde two-fluid model and a balance between gravity and turbulent fluctuations normal to tde axial flow direction. Stability analyses reveal tdat tde stratified/nonstratified transition must be addressed witd tde complete two-fluid model. Stratified flow is predicted by tde viscous Kelvin-Helmholtz (KH) analysis while in-viscid KH tdeory predicted tde ST&MI flow pattern. For tde dispersed flow pattern, tde predicted drop sizes from tde Hinze and Levich models are modified to account for tde effect of tde dispersed phase concentration. tde controlling parameter for tde coalescence phenomena is tde water fraction. tde model performance is excellent and compares well witd published data.
Acoustic and Petrophysical Properties of Seafloor Bedrocks
Authors: Assefa Solomon , Sothcott Jeremy
Published: December 2007

There are few published velocity and attenuation data for seafloor bedrocks at appropriate confining pressures (1 MPa to 10 MPa). Velocities and attenuations measured at low pressures are affected mainly by open microcracks. However, as the pressure is increased and the microcracks are closed, the effect of microcracks on the velocities and attenuations will be minimal. At elevated pressures, the velocities and attenuations in rocks depend primarily on the elastic moduli of the rock-forming minerals and porosity, which results from the degree of alteration and diagenetic processes that acted on the rocks. The aim of this paper is to investigate the effect of microcracks on the acoustic properties at low pressures (10 MPa effective pressure) and the relationship between the acoustic, petrophysical, and geological properties of seabed rocks at high pressure (40 MPa effective pressure), where the effect of microcracks is minimal. Laboratory measurements of acoustic velocity and attenuation of this kind give a better understanding of these properties at the appropriate pressure (depth) for rocks undergoing different geological (e.g., diagenesis) processes than those buried at greater depth.

We measured compressional- and shear-wave velocity and attenuation on a suite of seabed sedimentary and igneous rocks of the northern U.K. continental shelf at effective pressures (confining less pore-fluid pressure) ranging from 10 MPa to 40 MPa. The measurement frequencies range from 0.5 MHz to 1 MHz. We used Winkler and Plona's 1 pulse-echo method to measure velocity and attenuation (quality factor). The porosity and permeability of the rocks range from 0% to about 20% and 0 to about 5 md, respectively. X-ray diffraction (XRD) analysis, petrological studies of polished thin-sections, and scanning electron microscope (SEM) observations show that most of the sandstones have a significant clay content (e.g., kaolinite, illite, and chlorite) and fractures. Most of the igneous rocks are chloritized.

We show that the velocities and quality factors of the rocks studied are much lower than those of similar continental rocks. Microporosity formed by the alteration of feldspars, micas, and mafic minerals to clays (e.g., chloritization of pyroxenes) and the corresponding reduction of the elastic moduli are the major processes that result in low velocity and quality factors. Velocity and attenuation models of seabed rocks are critical for the interpretation of seismic data for rocks buried at greater depth. The results of this study suggest that values of velocities and quality factors used for modeling purposes should be lower than assumed normally.
Field Operational and Performance Issues of Polymeric Water-Control Agents
Authors: Lane R. H.
Published: December 2007

This paper describes field experience with low- and high-molecular-weight partially hydrolyzed polyacrylamide (PHPA) polymers crosslinked with Cr(III) carboxylate species. On the basis of that experience, the paper addresses successes and limitations in terms of downhole temperature, precooling, chemical delay of crosslink time, length of time for treatment application, quality control of polymers from different sources/batches, equipment considerations, and premature-gelation issues. The paper also visits some general field considerations, including the importance of robustness of the chemistry employed.
Two-Phase Pressure-Drop Predictions Across Gravel Pack
Authors: Ates Harun , Kelkar Mohan
Published: December 2007

In applying nodal analysis to optimize the performance of a single well, it is critical that we are able to estimate the pressure drop across each of the components of a complete well system, from the outer boundary of the reservoir to the sandface, from the tubing string to the separator including any restrictions, safety valves, and surface choke. Relationships for rate vs. pressure drop under single-and two-phase flow conditions are available for most of the components with the exception of perforations and gravel pack. This paper presents the procedure for calculating the pressure drop across perforations and gravel pack under two-phase flow conditions. Results are presented indicating the difference between single- and two-phase flow calculations. It is shown that if the two-phase flow is not properly accounted for, we can significantly underestimate the pressure drop across the gravel pack and perforations.
Productivity of Horizontal Sinks in the Presence of Distributed Fractures
Authors: Sato Kozo
Published: December 2007

The steady-state productivity (Jh) of horizontal sinks (hydraulically fractured wells or horizontal wells) in the presence of regularly arranged and stochastically distributed fractures is studied. Numerical experiments are conducted in two dimensions to investigate several factors affecting Jh, which include the number of fractures, the mean of fracture lengths, fracture inclination, and horizontal-sink length and location.

For 500 simulation outcomes, parametric correlations between Jh and possible regressor variables are obtained. It was found that the overall-fracture parameters (the number of fractures and the mean of fracture lengths) alone could not yield good correlations. Including near-sink fracture configurations in a set of regressor variables improves the quality. With the developed correlations, individual contributions of the horizontal sink, near-sink fractures, and overall fractures to Jh are examined. The findings obtained in this study are of help when designing horizontal sinks to be completed in fractured reservoirs.
Transient Behavior of Finite Conductivity Horizontal Fractures
Authors: Valkó Peter , Economides Michael J.
Published: December 2007

In this work a semi-analytical solution method is elaborated to obtain the transient behavior of a vertical well intersected by a finite conductivity horizontal ("pancake") fracture. Both the constant production rate and the constant drawdown cases are considered. Permeability anisotropy and non-homogeneous formation structure are incorporated into the model formulation. The results can be used to evaluate pressure transient testing and/or to forecast the production increase. Comparison with the uniform flux and infinite conductivity solutions brings light to the effects neglected in those approximations. Late time pseudoradial behavior is interpreted in terms of pseudo-skin factor and the issue of optimal fracture conductivity is addressed.
East Spar Development: NCC Buoy - The Vertical Submarine
Authors: Boyle E. C.
Published: December 2007

The remote East Spar gas/condensate field has been developed using a subsea production system operated by an unmanned navigation, communication, and control (NCC) buoy. The use of this type of sys- tem allows control of the field from any convenient location, with the command-response time and the cost of the facility almost complete- ly independent of the distance to the shore or host facility. Successes during the project (such as using model tests to prove the concept and using a tension-leg mooring system to reduce the motion response of the buoy) are discussed and compared to failures, like the weight and size growth of the structure, caused as the design requirements were finalized and external factors changed. The operation and layout of this facility is summarized, showing why it was described as a vertical submarine. Conclusions are drawn about the use of an NCC buoy to develop this field, showing that the main objectives have been achieved. The limited operating experience to date is also considered in the review of the design objectives. The paper concludes with the possibilities for the future of this type of concept.
Network Modeling of Three-Phase Flow in Porous Media
Authors: Fenwick Darryl H. , Blunt Martin J.
Published: December 2007

We present a network model of three-phase flow in water-wet porous media. To explain the high oil recoveries in gas injection and gravity drainage experiments, we show that the mechanism for oil recovery is flow through connected oil layers in the pore space that are on the order of a micron thick. We then describe a simple model for the configuration of oil, water, and gas in a single pore and present an approximate expression for the conductance of oil layers. We use this expression to derive the oil relative permeability when flow is dominated by layer drainage. We show that for low oil and water saturations kro∼So2, consistent with the results of several experiments. To predict kro for the full range of oil saturation we use a capillary equilibrium-based network model that can simulate any sequence of oil, water, and gas injection. We introduce a self-consistency procedure to ensure that the correct sequence of saturation changes is used in the network model to compute relative permeability. We then present relative permeabilities and oil recoveries for gas injection into different initial oil saturations, and for waterflooding a reservoir containing gas and oil. We show that the relative permeabilities are strongly affected by the fluid properties and by the type of displacement process.
New Fluosilicic Acid System Removes Deep Clay Damage
Authors: da Motta Eduardo P. , dos Santos J. Altamiro C. M.
Published: December 2007

Recent models for sandstone acidizing have shown that the secondary reaction of fluosilicic acid (H2SiF6) with clays plays a significant role in the removal of formation damage. The conventional wisdom is that possible precipitation during the secondary reactions can adversely affect treatment success. However, this paper presents laboratory experiments with Berea cores and two Brazilian sandstone cores, as well as with field tests, that show that fluosilicic acid can be injected, by itself, into a sandstone reservoir without causing any damage. In fact, mixtures of fluosilicic acid, with a proper amount of hydrochloric acid (HCl) or an organic acid such as acetic acid (HAc), have been able to improve the performance of two Brazilian water-injection wells by removing clay damage. These two wells, which were injecting 11 and 15 m3/d, respectively, are sustaining injection rates at or above the desired quota of 30 m3/d 5 months after the treatments. The treatments were monitored with a real-time monitoring program, which showed that the skin factor has dropped from about 30/40 to zero. Besides having a lower cost than conventional hydrofluoric acid (HF) mixtures, the main advantage of the new acid system is that it reacts mostly with clays and feldspars, but it almost does not react with quartz. Thus, it can dissolve damage without weakening the rock structure, which makes it suitable for deep damage removal. The low cost of H2SiF6, which is a byproduct of sodium fluoride manufacturing, also makes it a viable option for routine acidizing operations that normally would require the use of an HF acid system.
Probabilistic Reserves! Here at Last?
Authors: Capen E. C.
Published: December 2007

Recently, SPE and the World Petroleum Congresses (WPC) modified earlier definitions of reserves for the industry. Through much lobbying about improving the definitions, the committees generally clung to the past.

In truth, reserves have always been about probability because there has always been uncertainty as to proved, probable, and possible reserves. This paper proposes to dust off some of the mystery about how to deal with reserves probabilistically and correct some common procedures that do not follow the laws of probability and thus produce the wrong answer. For example, despite the reasonableness of the rule, it is illegal to add proved reserves from wells to get proved field or reservoir reserves. Every engineer who uses that method shortchanges his client and misleads the investors.
Comparisons of Uncoupled and Various Coupling Techniques for Practical Field Examples
Authors: Samier P. , Onaisi A. , Fontaine G.
Published: December 2007

Generally, in classical reservoir studies, the geomechanical behavior of the porous medium is taken into account by the rock compressibility. Inside the reservoir simulator, the rock compressibility is assumed to be constant or to vary with the pressure of the oil phase. It induces some changes in the porosity field.

During the depletion phase or the cold-water injection of high-pressure/high-temperature (HP/HT) reservoirs, the stress state in and around a reservoir can change dramatically. This process might result in rock movements such as compaction, induced fracturing, and enhancement of natural fractures and/or fault activation, which continuously modify the reservoir properties such as the permeabilities and the fault transmissibilities.

Modifications of such parameters strongly affect the flow pattern in the reservoir and ultimately the recovery factor.

To capture the link between flow and in-situ stresses, it becomes essential to conduct coupled reservoir-geomechanical simulations.

This paper compares the use of five types of approach for the reservoir simulations:

A classical approach with rock compressibility using only a reservoir simulator. A loose coupled approach between a reservoir simulator (finite volumes) and a geomechanical simulator (finite elements). At given user-defined steps, the hydrocarbon pressures calculated by the reservoir simulator are transmitted to the geomechanical tool, which computes the actual stresses and feeds back iteratively the modifications of the petrophysical properties (porosities and permeabilities) to the reservoir simulator. A one-way coupling: this approach is a simplification of the loose coupled approach in that the modifications are not fed back to the reservoir simulator. A simplified approach using permeability and porosity multipliers inside a reservoir simulator. These multipliers are user-defined curves and vary with the pressure of the oil phase. This approach uses only a reservoir simulator. A coupled approach in which the structural and the flow unknowns (displacement, pressure, and saturations) are solved simultaneously.

These approaches are compared for two validation cases and two field cases described in the following.
On Reservoir Fluid-Flow Control with Smart Completions
Authors: Ramakrishnan T. S.
Published: December 2007

Poor displacement efficiency in hydrocarbon formations is often caused by the natural variation in the mobility of fluids across the reservoir strata. Historically, completions with cemented casing, packers, conformance controlling fluids/gels, and selective perforations have been used to mitigate the disparities in water encroachment over the reservoir interval. Recently, completion technologies using downhole valves, which allow production and injection control over multiple zones, have become available. The central idea is that downhole control may be used to adjust flow distributions along the wellbore to correct undesired fluid-front movement.

In this paper, we address several technical issues related to downhole controls. We consider a single system comprising the reservoir, the completion, the measurement, and the feedback algorithm that adjusts flow-control devices, with quantitative models for each of the components. Both pressure and flow-rate control systems are discussed. Downhole control is modeled for electrical, reversible hydraulic, and unidirectional hydraulic valves. The design methodology for different valve systems is described and the disadvantages of hydraulic systems are discussed. In particular, it is shown that in conjunction with an automated feedback control, hydraulic valves will oscillate. Computations also show that all other factors remaining equal, these oscillations occur most easily in low-permeability zones. For unidirectional hydraulic valves, we also illustrate novel anticipatory control algorithms that prevent overshooting.

For communicating layered systems, a front movement equation is derived using perturbation techniques. This technique provides the zone of influence of wellbore flow-control devices, and illustrates the maximal benefit that may be obtained through down-hole control, thus providing a ready comparison with the cost of completion.
Assessment and Diagnosis of Inorganic-Scaling Potential Using Near-Infrared Technology for Effective Treatment
Authors: Ohen Henry A. , Williams Lee E. , Lynn Jack D. , Ali Liaqat
Published: December 2007

Inorganic scaling is a predominant formation-damage mechanism in most producing and injection wells worldwide. Scales are deposited from oilfield brines when there is a disturbance in ther-modynamic and chemical equilibrium. The degree of supersaturation caused by the disturbance in equilibrium can be increased to result in scaling by changes in fluid composition through adverse mixing and by changes in temperature and pressure.

Although a few cases have been reported of nonwater-producing oil wells that produced scales, typically oilfield scaling accompanies water production. Scaling problems during well development and supplemental fluid injection are primarily caused by mixing of two incompatible fluids, whereas production-related scaling is typically controlled by pressure and temperature. Acid or any common solvent cannot easily remove some types of scales like barium sulfate (BaSO4), which readily incorporates radioactive radium in its structure.

Therefore detection and prevention is critical wherever any precipitation or coprecipitation that includes BaSO4 may be taking place. As severity of scaling is controlled by temperature, pressure, and composition, the key to the detection, prevention, and effective treatment is a methodology to determine at what conditions in the reservoir or at what point in the well the scales are precipitated and deposited, and also to determine the type of scale. This is important because sometimes scales can be forming at a point in the wellbore without showing up at either the surface or at the sandface.

Near-infrared (NIR) technology has been used extensively in detecting the organic scales such as asphaltene deposits. To the best of our knowledge, this study presents the first extensive use of NIR technology to diagnose inorganic-scaling problems.

This paper presents several examples in which NIR technology has been used to detect the onset of inorganic scale as a function of pressure depletion at reservoir temperature for water from different fields. We also show how the NIR technology has been used to determine the effectiveness of various commercial inhibitors at reservoir conditions. We also present further screening of the inhibitors (selected on the basis of results of NIR tests) to determine their effective use in the field and the design of the inhibitor treatment for the producing wells.
Scale Control Within the North Sea Chalk/Limestone Reservoirs—The Challenge of Understanding and Optimizing Chemical-Placement Methods and Retention Mechanisms: Laboratory to Field
Authors: Jordan Myles M. , Sjursaether Karsten , Collins Ian R.
Published: December 2007

The scale-control challenges for two North Sea carbonate reservoirs are reviewed in this paper. While carbonate reservoirs are not the largest source of hydrocarbons within the North Sea, they are very significant on a global basis.

The mechanism of scale-inhibitor chemical retention observed for phosphonate, polymer, and vinyl sulfonate copolymer (VS-Co) inhibitors on carbonate-reservoir substrates is outlined. Chemical placement represents the most significant technical challenge when performing scale-inhibitor squeeze treatments into fractured chalk reservoirs. Examples from more than 50 field treatments applied in reservoirs E and V, in which both phosphonate and VS-Co chemicals have been deployed, are used to illustrate the difference in chemical retention observed in laboratory evaluations. The laboratory studies demonstrated clear potential for significant extension in treatment lifetime by changing from a phos-phonate to a VS-Co-based scale inhibitor. The selection and qualification of chemical-placement systems for deployment of inhibitors in fractured carbonate reservoirs are also outlined. To this end, novel technologies to enhance conventional scale-inhibitor-chemical placement are vital to economic success during waterflood projects.
Stabilizing Wellbores in Unconsolidated, Clay-Laden Formations
Authors: D. Nguyen Philip , Dusterhoft Ron G. , Ali Syed A. , Lockman Russell R.
Published: December 2007

This article presents results of laboratory and field testing regarding the effectiveness of an improved, one-component, low-viscosity resin-consolidation system. The system is designed to stabilize or strengthen the unconsolidated formation sand surrounding a wellbore and to overcome the effects of cyclic loading, while minimizing reduction of original permeability. Treatment-fluid volumes, overflush fluid, and the chemical composition of the consolidation material were found to directly impact the consolidation performance and the retained permeability of the treated formation sand. The treatment renders formation fines immobile so that migration and plugging do not occur.

This study determined that application of a consolidation material containing a specific solvent chemistry for clay-laden sands resulted in excellent strengths, even at high clay contents. This finding indicates that the consolidation material was drawn onto the mineral surfaces, resulting in minimal loss in effective porosity. Scanning electron micrographs of the consolidated-core material clearly revealed the entrapment of fines as the consolidation material formed a thin film on the mineral surfaces, causing little damage to the porosity and permeability of the formation.

Results of field testing indicate that the consolidation treatment effectively stopped the production of formation sand and fines while maintaining the production of the wells at desirable flow rates. The technique provides a very attractive alternative to conventional sand-control completions in lower quality reservoirs, as well as an effective through-tubing completion alternative.
Ramey's Wellbore Heat Transmission Revisited
Authors: Hagoort Jacques
Published: December 2007

In this work we assess Ramey's classic method for the calculation of temperatures in injection and production wells. We show that Ramey's method is an excellent approximation, except for an early transient period in which the calculated temperatures are significantly overestimated. We present a simple graphical correlation to estimate the length of this early transient period. We further demonstrate that Ramey's procedure for the estimation of overall heat-transfer coefficients holds good only for large values of the Fourier dimensionless time. Finally, we illustrate the results of this work by an example calculation of wellhead temperature in a flowing oil well.
Resistivity Modeling of Array Laterolog Tools: An Application in an Offshore Norway Clastic Reservoir
Authors: Galli M. T. , Gonfalini M. , Mele M. , Belík P. , Faivre O. , Jammes L. , Litman A.
Published: December 2007

Resistivity logs, while used extensively in the oil industry for the determination of water-saturation profiles and, consequently, for the quantification of hydrocarbon originally in place (HOIP), are strongly affected by environmental effects such as borehole, shoulder-bed resistivity contrasts, mud-filtrate invasion, dipping beds, and electrical anisotropy. It is well known by log interpreters that the combination of the different effects may strongly affect the estimation of hydrocarbon in place and hydrocarbon reserves. This paper highlights the strong reduction of the uncertainties in watersaturation determination and, consequently, the petrophysical characterization of the reservoir achieved by applying the appropriate 2D resistivity-modeling and -inversion techniques to two wells of the Norwegian offshore area. Both wells were drilled in a sandstone reservoir, with some thin-bedded intervals, and affected by the presence of anomalous invasion profiles.
Well Surveillance with a Permanent Downhole Multiphase Flowmeter
Authors: Webster M. , Richardson S. , Gabard-Cuoq C. , Fitzgerald J. B. , Stephenson K. E.
Published: December 2007

Flow rate and fluid type (phase) are two of the most fundamental parameters needed to characterize well performance. Traditional methods of estimating these parameters, particularly for real-time detection and diagnosis of production anomalies, have been limited by sampling frequency and data quality. This paper presents field-test results of a new type of downhole multiphase flowmeter, which confirm the value of permanent downhole metering. The meter contains only three sensors but is capable of direct multiphase-flow-rate and cut measurements without slip models, even in highly deviated, recirculating flow. The physics basis and flow-loop tests are discussed.
Lessons Learned From Using Viscoelastic Surfactants in Well Stimulation
Authors: Nasr-El-Din Hisham A. , Samuel Mathew
Published: December 2007

Viscoelastic surfactant systems are used in the industry for several applications. Initially, the application was focused on low-friction and solids-suspension (fracturing and CT-cleanout) characteristics of the fluid. In the last 4 years, the application of viscoelastic surfactants was extended to acid-based systems for carbonate stimulation. These surfactants have the ability to significantly increase the apparent viscosity and elastic properties of the treating fluids. This is because of the ability of surfactant monomers to associate and form rod-shaped micellar structures under certain conditions.

Viscoelastic surfactant-based acid systems have been used in Saudi Arabian fields in matrix acid stimulation, and in leakoff control acids during acid-fracturing treatments. These surfactants were used to provide diversion during acidizing of vertical, long horizontal, and multilateral wells. They were used in sour environments where hydrogen sulfide levels reached nearly 10 mol%. They were also utilized in gas wells to reduce acid leakoff, and create deep fractures in dolomitic carbonate reservoirs (250 to 275°F). In addition, they were successfully employed to stimulate seawater injectors and disposal wells where the bottomhole temperature was in the range of 100 to 150°F.

More than 250 wells (oil, gas, water injectors, and disposal wells) were treated with viscoelastic surfactant-based acid systems. The acid was placed either by bullheading, by using coiled tubing with or without a tractor. In some cases, these treatments included stages of emulsified or regular acids. All these wells responded positively to the treatment. There were no operational problems encountered during pumping these acids even when low-permeability reservoirs were treated. Because these acid systems do not contain polymers, there was no need to flow back water injectors. The spent acid in oil and gas wells was lifted from the treated wells in a very short period of time. Finally, wells treated with surfactant-based acid systems showed sustained performance for longer times than those treated with other acid systems.
Pressure Variations Inside the Hydraulic Fracture and Their Impact on Fracture Propagation, Conductivity, and Screenout
Authors: Daneshy A. Ali
Published: December 2007

Field measurements of fluid pressure inside hydraulic fractures have shown rapid pressure declines along the fracture length. The consequence of this pressure profile is rapidly tapering fracture width. This means that a disproportionate volume of fluid and proppant injected inside hydraulic fractures remains near the wellbore, thus creating excessive near-wellbore and substantially less far-field fracture conductivity. This explains why history matching of oil well production figures yields much lower effective fracture lengths than when the same exercise is performed for gas wells, as oil wells require higher fracture flow capacity because of their higher permeability.

The rapid tapering of the fracture width also restricts the movement of the proppant inside the fracture, causing its accumulation near the wellbore. As the treatment progresses, and if sufficient proppant volume has been injected inside the fracture, the near-wellbore segment of the fracture can begin to fill with proppant, thus reducing the open width available for further movement of the fluid. Essentially, accumulation of proppant near the wellbore reduces the fracture width available for fluid flow, which then results in higher frictional pressure losses inside the fracture, further skewing the pressure distribution and eventually leading to screenout.