bluuebunny/crossref_metadata_2025_split huggingface dataset:
Film-Thickness Distribution for Annular Flow in Directional Wells: Horizontal to Vertical
Authors: Paz R. J. , Shoham Ovadia 
Published: December 2007

Summary
An experimental and theoretical investigation has been carried out on two-phase annular flow in inclined pipes. The study focused on the effect of the inclination angle on the liquid film thickness distribution. A conductance multiprobe instrument was utilized to measure the local liquid film thickness around half of the pipe periphery for inclination angles of 90°, 75°, 60°, and 45° from the horizontal. A simple analytical model has been developed for the prediction of the liquid film thickness at the top and bottom of the pipe. The model is applicable for the entire range of inclination angles, from horizontal to vertical. Good agreement is observed between the prediction of the model and the experimental data collected in this study and from the literature.
A Contemporary Approach to Matrix Acidizing
Authors: Coulter G. R. , Jennings A. R. 
Published: December 2007

SummaryThis paper presents an updated look at the many variables associated with successful matrix acidizing. Damage types and formation characteristics significant when considering formation damage and damage removal are presented. Emphasis is placed on knowledge of formation mineralogy and temperature. The requirement for and the function of the many acid additives are discussed. General information and guidelines for matrix stimulation of carbonates and sandstones are provided.
Fracturing With a High-Viscosity, Cross-Linked GelContinuous Fracturing Technique
Authors: Free D.L. , Thompson J.E. 
Published: December 2007

Introduction
Highly viscous fracturing fluids that could be pumped at relatively high rates with acceptable friction pressure were first introduced 18 years ago. This viscous fluids were oil-water dispersions that created some problems because they required special mixing and pumping techniques. The fluids did, however, prove their value by creating wide, deeply penetrating fractures and by carrying high concentrations of propping agents. Since then, other high viscosity fluids have been introduced and their properties and effectiveness reported. Such fluids now properties and effectiveness reported. Such fluids now are used commonly in all areas. Because there is some variation in fluid requirements of different areas and formations, several types of fluids have evolved. All can be classed as viscous fracturing fluids. While these fluids have been used successfully, most have the same primary disadvantage: they must be batched mixed before use. Batch mixing requires that all water gelling agents be premixed in fracturing tanks before pumping. Often this premixed in fracturing tanks before pumping. Often this leads to additional rig-time expense for the operator and additional rig-time expense for the operator and additional equipment time and man hours for the service company. Also, if the procedure is not completed as planned, there can be considerable expense in preparation planned, there can be considerable expense in preparation of fluid that is not used. These expenses can become prohibitively high on large jobs, such as the prohibitively high on large jobs, such as the "massive-fracturing" type treatment. To overcome the disadvantages of batch mixing, specially prepared materials for gelling water have been developed that can be mixed continuously as the fluid is pumped down hole. These materials, first prepared from guar gum polymers, have been in use for 3 years and have proved polymers, have been in use for 3 years and have proved highly successful. More recently, lower residue guar derivatives have been used successfully.

Cross-Linked Guar Gels
Very high viscosities can be achieved by cross-linking the guar gels. However, preparation of cross-linked guar gels at the well location on a large volume basis has been troublesome and time consuming in the past because of the required batch-mixing technique. That is, the guar gelling agent and cross-linker are premixed in the fracturing water. Adjustments of the fluid's pH are often necessary and present problems in achieving a uniform pH in large fracturing tanks. The guar gelling agent hydrates and produces a high-viscosity solution.
JPT
P. 119
Nonisothermal Gravitational Composition Variation in a Large Deep-water Field
Authors: Padua K. G. de Oliveira 
Published: December 2007

Summary
This paper examines the oil composition distribution of a large deep-water field which the temperature variation, because of the water depth (800 to 2000 m), is in the opposite direction of the Earth's thermal gradient. The main practical objective is to investigate if the oil distribution would suggest fluid connectivity along this 40 km long and 15 km wide oil field. This could significantly impact the appraisal and development phases of the field. The methodology adopted here includes reservoir geochemistry, fitting of a single equation of state, compositional simulation, and thermodynamic equilibrium. The results from reservoir geochemistry indicate a common oil source, different migration pulses, a lateral migration path and some hydrocarbon mixing after filling process. A single equation of state is set to represent the oil behavior for the whole field. The successful matching is achieved by means of splitting the heaviest component and so reducing the molar concentration of the pseudocomponent on a single regression procedure. Compositional simulation runs, representing the secondary migration, suggest spots of gas caused by phase changes. During the filling process, the results show heavier oil in front of the upward flow. During the mixing process, the gravitational segregation seeks to reverse this trend. A new thermodynamic equilibrium model that accounts for the effect of temperature shows an increase of oil segregation with a temperature gradient opposite to the thermal's gradient. The results suggest thermodynamic equilibrium of oils in an area of the reservoir. This may suggest reservoir connectivity. In the area the oils are in thermodynamic equilibrium, fluid composition and properties are extrapolated to different depths while function of their respective temperatures.
Practical Considerations in the Analysis of Gas-Condensate Well Tests
Authors: Raghavan R. , Chu Wei Chun , Jones J. R. 
Published: December 2007

Summary
Several pressure buildup tests are analyzed with a view to evaluate the potential of the ideas given in the literature. A broad range of tests is examined to demonstrate the characteristics of responses in wells producing below the dew point. Methods to obtain quantitative information that is consistent for different tests are outlined. The specific contributions of this article are as follows. First, in this article we examine field data, second, we look at multiple rates, third, we examine unfractured and fractured wells, fourth, we look at wells that have been produced for a short time and those produced for a long time, fifth, we consider both depletion-type and cycling scenarios, and, sixth we tie pressure data to relative permeability and PVT data. Many of these issues are addressed for the first time.
Selective Conformance Control in Heterogeneous Reservoirs by Use of Unstable, Reactive Displacements
Authors: Thompson K. E. , Kwon Ohseong 
Published: December 2007

Summary
This paper examines a conformance control technique in which gel is placed into a heterogeneous porous medium by first injecting a high-viscosity uncrosslinked polymer solution and second, a low-viscosity crosslinker. The latter step causes an unstable displacement to occur and allows the crosslinker to flow selectively into high-permeability strata. A visual flow cell was used to test the procedure, and complete fluid diversion was achieved in a dual-zone medium with a 4:1 permeability ratio. In addition, experiments and numerical simulations were used to study fundamental changes in viscous fingering due to the crosslinker-polymer reaction. When the crosslinking reaction is fast enough so that it occurs during injection, the viscous instability becomes somewhat damped, resulting in less distinct fingers and a nearly plug-flow displacement in some cases. The differences are because gelation causes a large pressure gradient to form just behind the displacement front, whereas unreactive fingering is caused by a small pressure gradient within the fingering zone.
In-Situ Polymerization of an Inflatable Composite Sleeve To Reline Damaged Tubing and Shut Off Perforations
Authors: Saltel J. L. , Leighton J. R. N. , Faure A. M. , Baaijens Thijs 
Published: December 2007

Summary
Finding an effective solution to seal-off perforations, whether it be to reduce gas flow, reduce water cut, or to modify injection profiles, has long been a subject of concern. Several solutions for through tubing shut-off have been tried with a varying level of success.
After several years of testing a new technology has been developed to manufacture a composite sleeve using elastomers, fibers, and thermosetting resins. The sleeve is run-in on electric wireline, inflated to push the composite against the inside of the casing, then heated to polymerize the resins. The running equipment is extracted to leave a pressure resistant inner lining in place. There is little diameter loss, leaning access to the well below, and opening up applications for tubing repair. Following successful field trials commercial operations have begun.
The technology has been used not only for water and gas shut-off, but also for repairing damaged casings and tubings. This paper introduces the technology, describes the equipment used, and runs through the development and testing phases prior to beginning field operations. Typical examples of jobs carried out are cited, and some case histories are developed in greater detail.
Use of Full-Field Simulation to Design a Miscible CO2 Flood
Authors: Brinkman F. P. , Kane T. V. , McCullough R. R. , Miertschin J. W. 
Published: December 2007

Summary
A study using full-field reservoir modeling optimized the design of a miscible CO2 flood project for the Sharon Ridge Canyon Unit. The study began with extensive data gathering in the field and building a full-field three-dimensional geologic model. A full-field simulation model with relatively coarse gridding was subsequently built and used to history match the waterflood. This waterflood model highlighted areas in the field with current high oil saturations as priority targets for CO2 flooding and generated a forecast of reserves from continued waterflooding. Predictions for the CO2 flood used an in-house four-component simulator (stock tank oil, solution gas, water, CO2). A full-field CO2 model with more finely gridded patterns was built using oil saturations and pressures at the end of history in the waterflood model. The CO2 model identified the best patterns for CO2 flooding and was instrumental in selecting a strategy for sizing the initial flood area and in determining the size, location, and timing of future expansions of the CO2 flood.
Reliability Analysis of Permanent Downhole Monitoring Systems
Authors: van Gisbergen S. J. C. H. M. , Vandeweijer A. A. H. 
Published: December 2007

Summary
Permanent downhole gauge (PDG) systems have been installed in many oil and gas wells. These systems improve reservoir management and production optimization. Currently, more complex downhole monitoring and control systems are being installed in what are often called "Intelligent Wells." Reliability is a critical aspect for all these systems.
We evaluated the performance of 952 pressure- and temperaturemonitoring systems installed since 1987. The 5-year survival probability of these systems improved from 40% for systems installed in the period 1987–88 to 75% for the period 1991–92. No further improvements have been observed from 1992, resulting in a 5-year survival probability of 69% for the period 1993–98.
Failure modes have been evaluated and could be attributed primarily to the downhole gauge and to the cable. Based on these findings, recommendations have been made to achieve reliability improvements.
Simulation of Produced Water Reinjection Under Fracturing Conditions
Authors: van den Hoek P. J. , Matsuura Tsuyoshi , de Kroon Michiel , Gheissary Ghassem 
Published: December 2007

SummaryAn essential difference between conventional waterflood fracturing and unfiltered produced water reinjection (PWRI) under fracturing conditions is that in the latter case, the fracture conductivity cannot be assumed infinite anymore as a result of fracture fillup with injected solids. This relates to the important PWRI issue of where the injected solids go. Using numerical model calculations, we show that the pressure drop over a finite conductivity fracture can lead to a significant increase in fracture volume without necessarily leading to a significantly higher injection pressure. Thus, a picture emerges in which the fracture conductivity "adjusts" itself in order to accommodate injected solids. This picture allows the computation of well injectivity as a function of total injected water volume, solids loading, etc. This concept can also be used to qualitatively explain the PWRI field observation that injectivity appears to be partially or fully reversible as a function of water quality.A field example from the Middle East is presented. The effect of parameters such as water quality, formation stiffness, and filter cake permeability on well injectivity and fracture size is discussed. It is shown that for most practical applications, an approximate analytical formulation for the computation of well injectivity and fracture size provides good results.
Effect of Near-Wellbore Fracture Geometry on Fracture Execution and Post-Treatment Well Production of Deviated and Horizontal Wells
Authors: Chen Zhongming , Economides M. J. 
Published: December 2007

Summary
The near-wellbore fracture geometry is important to hydraulic fracture execution and the subsequent post-treatment well performance. A fracture from an arbitrarily oriented well "cuts" the wellbore at an angle and this limits the communication between the wellbore and reservoir. The stress concentration around the wellbore further complicates the near-wellbore fracture geometry. The fracture width at the wellbore can be much smaller than the maximum width, or it may even close when the fracturing pressure decreases below some critical value. The limited communication path may cause a "screenout" during fracture execution or large reduction in the subsequent production because of choked fracture effects. This paper first discusses fracturing conditions for an optimal communication path between the wellbore and the reservoir. The near-wellbore fracture geometry is then determined. The effects of this fracture geometry on fracture execution and production are discussed. Critical fracturing pressures are also calculated for different wellbore orientations and in-situ principal stress magnitudes. Guidelines are provided to enhance the success of fracturing treatments.
Underbalance or Extreme Overbalance
Authors: Behrmann L. A. , McDonald Bryan 
Published: December 2007

Summary
Application of an extreme overbalance, sufficient to fracture the reservoir formation, applied either during or after perforating was first presented as an alternate completion technique during the 1993 Fall SPE Conference.1 During the ensuing two years, a number of jobs have been run by different operators in a variety of formations with varying applications. The primary question asked by an operator relates to the benefit of extreme overbalance (EOB) versus current perforation techniques of underbalance (UB) or modest overbalance for well control. Of course this question spawns a whole set of new questions about when and how to use and the benefits and risks of the EOB. EOB, as used in this paper, includes extreme overbalance perforating and rapid overpressured perforation extension. This paper compares and contrasts UB and EOB strengths and weaknesses and provides recommendations of when and why to use the different techniques. Field examples are provided of successful and unsuccessful application of EOB completions.
High-Permeability Channels in Proppant Packs Containing Random Fibers
Authors: Howard P. R. , James S. G. , Milton-Tayler David 
Published: December 2007

SummaryThis paper discusses laboratory studies to determine the nature of channel growth and stability in proppant packs with and without fibers. Tests were performed with proppant packs in three different types of experiments using natural sand and ceramic proppants, gas and water flow, and either perforations or an open proppant pack face. Proppant packs without fibers fail at low fluid velocities by the formation of voids at perforations or across the entire front ofthe pack. In proppant packs without fibers, channels form only in cases when packing is imperfect. Proppant packs with fibers form channels 2-10 cm wide, depending on fluid velocity. The channel length increases in stepwise progression with increasing flow rate (velocity). The proppant pack on either side of the channel supports the closure stress. Channels are stable over time at constant flow rate and remain stable during closure stress cycling. Channels grew with fibers in all conditions tested. Random fibers mixed with the proppant extend the fluid velocity range for channel growth to much higher values.
Evaluation of Clay Stabilizers for a Sandstone Field in Central Saudi Arabia
Authors: Nasr-El-Din H. A. , Al-Mulhem A. A. , Lynn J. D. 
Published: December 2007

Summary
An oil field in central Saudi Arabia produces super-light crude from a sandstone reservoir. The formation contains up to 7.0 wt% authigenic clays dominated by kaolinite and illite/montmorillonite mixed layer clays. To mitigate sand production and improve well productivity, a frac pack stimulation treatment was conducted on most producing wells in this field. The treatment introduced several fluids, which might invade the formation and induce formation damage.
An experimental study was conducted to determine potential formation damage due to fines migration and clay swelling, and to design an effective clay stabilizer treatment. The work included performing coreflood experiments using reservoir cores under reservoir conditions. The critical salt concentration (defined, as the salt concentration below which there is loss of permeability) was first determined. Several commercial clay stabilizers, cationic polymers, were evaluated. The effects of stabilizer type, concentration and acids on core permeability were investigated in detail.
The experimental results indicated that the critical salt concentration (KCl brine) was nearly 5 wt%. Severe loss of permeability was observed when brines of lower salt concentrations were injected into reservoir cores. The effectiveness of clay stabilizers was found to be a function of chemical type and concentration. Some ofthe chemicals caused loss of injectivity at higher concentrations. It was found that these chemicals did not readily dissolve in water and formed fish eyes. When these chemicals were injected into reservoir cores, they formed an external filter cake, which caused loss of permeability. Good mixing of the stabilizer and proper filtration solved this problem. Hydrochloric acid at 15 wt% did improve the performance of at least one of the clay stabilizers examined.
Based on lab testing, a cost effective clay stabilizer was tested in the field. Field results indicated that the chemical did not cause loss of injectivity, and minimized formation damage due to fines migration and clay swelling.
Managing Structural Uncertainty in a Mature Field for Optimal Well Placement
Authors: Vincent Gilles , Corre Bernard , Thore Pierre 
Published: December 2007

SummaryThis paper describes a reservoir simulation study of a mature field. The objective of the study was to decide whether to drill an additional well and, if so, to determine its optimum location. An original approach to history-matching the model and accounting for structural uncertainty was adopted and we come to the following conclusions:The structural map can be used as a history matching parameter, Maps with the same original oil in place (OOIP) can lead to quite different productions, The same production can be obtained from different maps having different OOIP, The choice of complementary development schemes must take the nonuniqueness of the history match into account in order to minimize risk, Demonstration of the use of experimental design techniques in accounting for and managing structural uncertainty.
Geochemistry in an Integrated Study of Reservoir Compartmentalization at Ewing Bank 873, Offshore Gulf of Mexico
Authors: Edman J. D. , Burk M. K. 
Published: December 2007

SummaryEwing Bank 873 is an offshore Gulf of Mexico field discovered in 1991 in 775 ft of water. The discovery well was drilled on a seismic amplitude anomaly on the flank of a salt withdrawal mini-basin. Field development began in 1994, and in mid-1998 daily production from the Bulminella 1 reservoir averaged 40,000 BOPD and 32 × 106 ft3/D of gas. The Bul 1 reservoir in this combination structural-stratigraphic trap consists of six stacked and overlapping Pliocene turbidite sand lobes. In turn, integration of seismic, well log, geochemical and pressure data indicates these six turbidite lobes comprise three compartments. All of the various data types give constraints on different aspects of compart-mentalization, but at the stratigraphically complex Ewing Bank 873 field, geochemical analyses provided key information unavailable through any other means. These geochemical analyses were performed as individual wells in the field went on production and immediately provided information regarding fluid communication and reservoir connectivity that was missing from earlier interpretations based solely on seismic and log data. Early recognition of three reservoir compartments using geochemical data also helped constrain preliminary stratigraphic interpretations and provided initial input for flow units and reservoir simulation models. The geochemical information further provided advance notice of economically significant oil quality variations in the three compartments. These fluid variabilities were later substantiated by pressure/volume/temperature analyses and include notable differences in oil gravity, weight percent sulfur, viscosity and solution gas. Integrating all available data shows there are three compartments at Ewing Bank 873 and each compartment comprises different turbidite sand lobes and exhibits its own characteristic pressure regime and fluid properties. The early indications of both compartmentalization and variation in fluid properties by the geochemical analyses contributed significantly to improved field recovery and economics by allowing fewer and better placed wells to be drilled.
Simultaneous Production of Gas Cap and Oil Column With Water Injection at the Gas/Oil Contact
Authors: Billiter T. C. , Dandona A. K. 
Published: December 2007

Summary
The conventional way to produce an oil reservoir that has a gas cap is to produce only from the oil column while keeping the gas cap in place so that it can expand to provide pressure support. Depending upon the geometry, reservoir dip angle, and oil production rates, gas can either cone down to the oil producers or breakthrough as a front, leading to substantial increases in the gas-oil ratios of the oil producers. This paper presents a unique production methodology of simultaneously producing the gas cap and oil column while injecting water at the gas-oil contact to create a water barrier to separate the gas cap and oil column. This methodology has application in reservoirs with a low-dip angle, large gas cap, and a low residual gas saturation to water. It is demonstrated that the net present value of the project is improved if there is an immediate market for gas. Geostatistical reservoir models are used to demonstrate that the gas cap recovery is minimally impacted by heterogeneities.