bluuebunny/crossref_metadata_2025_split huggingface dataset:
New Cementing Technology Cures 40-Year-Old Squeeze Problems
Authors: Farkas R. F. , England K. W. , Roy M. L. , Dickinson M. , Samuel M. , Robert E. Hart 
Published: December 2007

Abstract
Remedial cementing using recently developed engineered micro-cement slurries allows small channels to be efficiently filled with cementitious materials, developing a permanent, high quality seal with high compressive strength and low permeability. Deeper penetration is achieved over conventional micro-cement slurries by improving axial fluid loss control through particle size distribution adjustments, and not from using small particles alone. This new technology has been extremely effective in remedial cement squeeze treatments, where synthetic and conventional cement systems have failed over the past 40 years.
The packing volume concept separates engineered slurries from conventional slurries. Engineered micro-cement slurries incorporate a particle size distribution that allows deeper penetration without bridging, premature viscosification or dehydration. The slurry has extremely low fluid loss, low plastic viscosity, lower yield points and better slurry stability with respect to free water and sedimentation. This slurry has superior injectivity over previous oil field cements, however, placement procedures do not follow conventional cement squeezing wisdom. When this material is placed into the channel, crack or perforation, the typical increase in pressure response that is seen during conventional squeeze treatments may not be observed.
This technology has been proven to be successful in more than forty wells to-date. In the New Hope field of East Texas, and in particular the Bacon and Hill Sand formations, up to nine squeeze attempts were performed on individual wells, without establishing a permanent hydraulic seal using various conventional cement systems and techniques. Conversely, in the same field, seven barrels of the engineered micro-cement slurry were placed on the first attempt, achieving the isolation required for re-completion. The application of this technology has also experienced good success in the Canadian shallow gas, and heavy oil markets. The shallow gas fields are located in Southeastern Alberta, near Medicine Hat, and the heavy oil fields are located in Northeastern Alberta in the Wainwright area.
Interpretation Of Chemical And Physical Measurements From An In Situ Coal Gasification Experiment
Authors: Brandenburg Charles F. , Reed Ray P. , Boyd Michael R. , Northrop David A. 
Published: December 2007

Brandenburg, Charles F., Laramie Energy Research Center, U.S. ERDA, Reed, Ray P., Sandia Laboratories, Albuquerque, Boyd, Michael R., Laramie Energy Research Center, U.S. ERDA, Northrop, David A., Sandia Laboratories, Albuquerque and Jennings, James W., University of Wyoming and Laramie Energy Research Center, U.S. ERDA.
American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Abstract
A second underground coal gasification experiment is being conducted at the Laramie Energy Research Center's field site near Hanna, Wyoming. This paper presents the results from the first phase of this Hanna II experiment in which coal seam permeability was evaluated, pneumatic linking and linking via reverse combustion were studied, and a sustained gasification process was maintained between the two linked vertical wells. Extensive in situ and surface process instrumentation have provided considerable information on the chemical and physical mechanisms involved in underground coal gasification. Air injection alone did not increase permeability to levels which would allow sustained gasification. Reverse combustion linking was determined to be a local, relatively low temperature process which advanced at a 5 ft/day rate and produced a high permeability carbonized path, Subsequent gasification was completed over a 38 day period. Overall, injection of 1.9 MM scf/day of air yielded 2.7 MMscf/day of gas with a heating value of 152 Btu/scf. Material balance calculations indicate that 1688 tons of coal in place were utilized. Specific discussion of reaction front configurations and interpretation of in situ thermometry are included.

Introduction
Underground coal gasification (UCG) has been the subject of investigations for more than 100 years. The process has been shown to be technically feasible in several experiments, but previously has been economically unattractive in competition with petroleum resources. The recent development of shortages of inexpensive petroleum fuels has resulted in rekindled petroleum fuels has resulted in rekindled interest in research on efficient in situ gasification of coals in the United States using modern techniques which were not available to earlier investigators.
Russian activities in underground gasification of coal have been the most sustained. Electricity has been generated from low Btu gas at several large scale plants in the Soviet Union from plants in the Soviet Union from subbituminous coals and lignites since 1960. Recently, diminished Soviet utilization of UCG for energy production is believed due to the discovery of adequate local petroleum fuel sources.
Foamy Oil Flow in Primary Production of Heavy Oil under Solution Gas Drive
Authors: Maini Brij B. 
Published: December 2007

Abstract
Foamy oil flow has received considerable attention in the literature in last several years. It is believed to be a key factor in producing the higher than expected well rates and the high recovery factors observed in several Canadian and Venezuelan reservoirs. However, beyond the recognition that it may involve dispersed flow of gas, there is little agreement as to what the underlying mechanisms are.
This paper presents a new mechanistic model of foamy solution gas drive and experimental evidence in support of the model. The main hypothesis in this model is that foamy oil flow is simply two-phase gas-oil flow at high capillary numbers. It occurs when the viscous forces become strong enough to mobilize gas ganglia growing from bubble nucleation sites.
The evidence in support of the existence of dispersed flow in solution gas drive in viscous oil systems comes from the effect of depletion rate on the performance of laboratory scale solution gas drive tests. These tests show that the high rate of pressure depletion at the production port results in: (1) a much higher oil recovery factor and (2) a high pressure-gradient within the sand-pack. Relatively high pressure-gradient persists throughout the duration of the high rate test and declines very slowly even after the flow has virtually stopped. It implies that the mobility of the free gas is exceedingly small, which strongly suggests that the gas is not continuous. By contrast, a high pressure-gradient never develops in slow depletion tests.
The evidence in support of the suggested form of dispersed flow comes from visual observations in etched glass micromodels. These tests show that the dispersion is not a result of nucleation of a very large number of bubbles but forms by break-up of a much smaller number of nucleated bubbles which become mobilized in the presence of high pressure gradient.
Finally the conditions under which this type of dispersed flow is likely to occur in the field are discussed.
Experimental Modelling of the SAGD Process – Enhancing SAGD Performance with Periodic Stimulation of the Horizontal Producer
Authors: Sasaki K. , Akibayashi S. , Yazawa N. , Doan Q. , Farouq Ali S. M. 
Published: December 2007

Abstract
Experiments on initial stages of the steam-assisted gravity drainage (SAGD) process were carried out, using 2-D scaled reservoir models, to investigate production process and performance. Expansion of the initial steam chamber, its shape and area, and temperature distributions were visualized using video and thermal-video pictures. The relationship between isotherms and steam chamber interface was investigated to study the drainage mechanism. The temperature at the interface where the steam chamber was expanding was observed to remain nearly constant at 80°C. Effect of vertical spacing between the two horizontal wells on oil recovery was also investigated. For the case of conventional SAGD, oil production rate increased with increasing vertical spacing; however, the lead time for the gravity drainage to initiate oil production became longer. The results suggest that L can be used as a governing factor to evaluate production rate and lead time in the initial stage of the SAGD process. Based on these experimental results, the SAGD process was modified: the lower production well was intermittently stimulated by steam injection, in conjunction with continuous steam injection in the upper horizontal injector. Using the modified process (named SAGD-ISSLW), the time to generate near breakthrough condition between two wells was shortened, and oil production was enhanced at the rising chamber stage compared with that of the conventional SAGD process.
Heterogeneity Effects on the Storage and Production of Gas from Coal Seams
Authors: Özgen Karacan C. , Okandan Ender 
Published: December 2007

Abstract
This paper presents the results of the experiments conducted on two structurally different coals from Turkey to investigate the effect of different heterogeneities on gas flow and storage in coal beds. Gas flow experiments were conducted on 3.8 cm diameter core plugs of these coals using xenon as the gas phase. Dual energy CT imaging technique was used to visualize the flow and storage of gas along the coal core to get qualitative and quantitative data from the images. After storage experiments end, nitrogen injection was performed to recover the stored gas from coal to represent an enhanced gas recovery operation. An analytical solution to this phase of one specific experiment was proposed to be able to calculate the diffusion coefficients from the gas recovery data calculated from CT images. The results of the experiments were analyzed to show the storage capacities of these two coals. The effect of different coal structures on the gas transport and storage and the matrix/fracture interactions were discussed by making a pixel based analysis and coupling it with the microstructure of coal investigated with scanning electron microscopy (SEM).
Results show that, if the coal is structurally heterogeneous in the sense that there will be different layers of mineral and organic matrix, there will be different zones that affect the storage and transport of gas. Due to these heterogeneities, gas recovery by nitrogen injection is not efficient at some regions. On the other hand, the coal that is more homogeneous has a higher storage capacity due to its microporous structure. In this coal, even if there are mineral fillings in the micropores, such mineral inclusions do not have an adverse effect on gas storage and transport as evidenced from CT images.
Scaling Up Matrix-Fracture Transfers in Dual-Porosity Models: Theory and Application
Authors: Bourbiaux B. , Granet S. , Landereau P. , Noetinger B. , Sarda S. , Sabathier J. C. 
Published: December 2007

Abstract
The dual-porosity model concept has been introduced to simulate flows through naturally-fractured reservoirs because of the specificity of those media: fluids are mainly stored in the matrix and flow to the wells through the fracture system. A simplified formulation of matrix-fracture fluid transfers at the scale of a simulator cell uses a pseudo-steady-state (PSS) transfer equation involving a constant exchange coefficient also called shape factor. The shape factor has long remained controversial because a theoretical framework was missing and evidence was given of its dependence on the mechanism of flow.
This paper presents different approaches to determine the matrix-fracture transfer behavior and derive the best approximate expression of the shape factor. These methods make use of the joint element technique for discretizing the actual fractured medium and are based on either (a) direct simulation of flow exchanges at local scale, (b) the application of upscaling theory, or (c) the implementation of a novel random walk method.
A resolution example is given for a realistic image of a fractured medium in 2D single-phase flow conditions. The whole process of matrix-fracture transfer, including the initial transient states, has been determined from local-scale simulation. All upscaling methods lead to the same approximate expression of the shape factor to be used in the PSS equation describing matrix-fracture transfer. This shape factor is expressed versus equivalent block dimensions, which are in practice determined with a recently-developed methodology involving geological image processing.
Then, an extension to multiphase flow conditions is presented. The local-scale simulation approach is used to compute the exact transient water-oil capillary transfers at dual-porosity cell scale. These transfers are quite well reproduced with a PSS formulation incorporating the shape factor expression defined for single-phase transfers. A transient shape factor, formulated versus simulator unknowns, has also been tested. It turns out that capillary transfers can be reproduced with a dual-porosity simulator without resorting to any parameter tuning.
To conclude, reliable simulation tool and upscaling methods are now available to compute matrix-fracture transfers on actual fractured media and derive the optimal PSS formulation to be used in dual-porosity simulators.
Achieving Technical Excellence and Improved Results through a Strategic Business Alliance
Authors: Chmilowski Walt , Dole Stephen A. 
Published: December 2007

Abstract
PanCanadian Petroleum Limited and Dowell, Division of Schlumberger Canada Limited formed a strategic alliance for well stimulation services in 1993. The difficulty of initiating the relationship and then growing the alliance over time has resulted in many challenges and provided many rewards. The working arrangement was built on a win/win philosophy of openness and mutual trust. A shared risk/reward relationship was developed to provide incentive to both companies to continuously improve the process and reduce costs. Objectives of the alliance were to reduce cost per unit of hydrocarbon recovered, improve productivity, and improve the profitability of both companies while maintaining the present outstanding safety and environmental record. Immediate benefits from the relationship were a more efficient usage of resources, reduction in redundancy of efforts between the corporations, better treatment design that resulted in improved well productivity in spite of limited well information. There have been a number of occasions where the relationship has grown and times where the relationship has experienced major challenges. Through the efforts of key team members, issues were resolved with the relationship now stronger than ever and new initiatives for mutual benefit are ongoing.
This paper discusses the real-life issues and positive as well as negative experiences encountered in this business relationship and how its chances of success have been improved by both parties.
Liquid Carry-over in Gas-Liquid Cylindrical Cyclone Compact Separators
Authors: Chirinos W. A. , Gomez L. E. , Wang S. , Mohan R. , Shoham O. , Kouba G. 
Published: December 2007

Abstract
The liquid carry-over phenomenon in Gas-Liquid Cylindrical Cyclone (GLCC©1) compact separators has been studied experimentally and theoretically.
Experimental data have been acquired including the operational envelope for liquid carry-over and percent liquid carry-over beyond the operational envelope. The data show that at low gas and high liquid flow rates, under churn flow conditions in the upper part of the GLCC©, large amount of liquid can be carried over relatively easily. On the other hand, at high gas and low liquid flow rates, under annular flow conditions, one should exceed the operational envelope significantly in order to have large amount of liquid carryover.
A mechanistic model has been developed for the prediction of the percent liquid carry-over beyond the operational envelope, for churn flow conditions. An existing model for the prediction of the operational envelope for liquid carry-over has been extended to high-pressure conditions, including improved models for zero-net liquid flow holdup, droplet region and blowout and critical velocities.
Comparisons between the new mechanistic model predictions for percent liquid carry-over with the experimental data, under churn flow conditions, show a good agreement. Also, in the lack of experimental data, the predictions of the operational envelope for liquid carry-over at high-pressure conditions show reasonable trends.
Modeling of Pigging Operations
Authors: Lima P. C. R. , Yeung H. 
Published: December 2007

Abstract
More and more transient gas-liquid operations in pipes has been successfully applied in the oil and gas industry. Pigging operation in two-phase pipelines to remove liquid accumulation or for cleaning purpose is an important transient operation. Another important operation is the injection of gas to transport the accumulated liquid in the pipeline to process facilities. Analysis of such transient two-phase flow in a pipeline is necessary not only for designing the liquid and gas handling facilities, but also for safe operating procedure. In pipeline-riser system such operations cause even more severe change in flow conditions. A two-fluid model has been developed to determine the transient behavior of fluids during these operations. The derived one-dimensional set of equations for each flow pattern describe the flow of fluids in all regions. Semi-implicit finite difference schemes were used to solve the initial and boundary value problem for each phase of the pigging process: gas/pig injection, gas shut-in, slug production and gas flow out of the system. An extensive experimental program has been carried out to acquire two-phase transient flow and pigging data on a 67 m long, 2 in diameter pipeline-riser system. A computer based data acquisition system has been utilized to obtains rapidly changing and detailed information of the flow behavior during the transient tests. The model compares well with the experimental data for characteristics such as inlet pressure, hold-up and pig velocity.
Variable Wellbore Storage Models for a Dual-Volume Wellbore
Authors: Spivey J. P. , Lee W. J. 
Published: December 2007

Abstract
Two new composite, or dual-volume, wellbore models are presented. Both models describe a two-compartment wellbore coupled through a pseudosteady-state flow equation. The models differ in how the wellbore is coupled to the reservoir.
The first model describes the pressure response in a well with a "leaky packer". This model may exhibit two unit-slope lines during wellbore storage, one at earliest times corresponding to the volume of the tubing, and a second one corresponding to the volume of the tubing plus the tubing-casing annulus.
Gringarten noted that apparent wellbore storage coefficients for naturally fractured reservoirs are often one or two orders of magnitude higher than calculated from wellbore geometry, and attributed this effect to storage in natural fractures intersecting the wellbore.1 The second, "near-wellbore fracture storage," model accounts for storage in the fracture system intersecting the wellbore, completion damage, and storage in the wellbore proper.
Both models give pressure responses that are very similar to those exhibited by the model proposed by Fair to describe phase segregation and thermal effects.2,3 This may explain the success of the Fair model in modeling many situations in which neither phase segregation nor thermal effects are likely to occur.
The "near-wellbore fracture storage" model also gives a pressure response that is almost identical to that exhibited by a pseudosteady-state dual porosity reservoir with wellbore storage. Gringarten observed that a majority of tests in fractured reservoirs appear to exhibit pseudosteady-state rather than transient dual porosity behavior.1 The proposed "near-wellbore fracture storage" model may account for the behavior interpreted as pseudosteady state dual porosity in many of these cases.
StarWars Laser Technology for Gas Drilling and Completions in the 21st Century
Authors: O'Brien D. G. , Graves R. M. , O'Brien E. A. 
Published: December 2007

Abstract
This paper describes results of the second phase of a GasResearch Institute (GRI) funded research program. Theoverall purpose of this research is to advance a fundamentalchange in the methods currently used to drill and completenatural gas wells applying the U.S. Defense Department'sStarWars laser technology. Results of tests conducted at theU.S. Air Force's high power laser research facilities arepresented. This phase of the research has used the ChemicalOxygen-Iodine Laser (COIL) high-powered laser invented bythe U.S. Air Force in 1977 for air-to-air defense. Located bof[b-dghj-npqrsvwxyz] U.S. Air Force Research Laboratory's Directed EnergyDirectorate, Kirtland Air Force Base, New Mexico, COIL hasgained notoriety as an airborne laser tactical weapon capableof tracking and destroying missiles. More than 100 rocksamples – including sandstones, limestones, shales, salt, granites and concrete – were exposed to laser beams ofvarying power and duration. The results were encouraging inthat the laser was able to penetrate all rock types. Samplessaturated with water, brine, oil and gas were also tested tomore accurately simulate the downhole drilling environment.The effects of vapor interference, gas atmosphere, confiningrock stresses and operating the laser in continuous andchopped modes will be discussed.
The basic research conducted on laser-rock-fluidinteractions is helping provide the foundation on which todetermine the benefits of using StarWars laser technology fordrilling and completing natural gas wells.
Influence of Drillpipe Rotation and Eccentricity on Pressure Drop over Borehole during Drilling
Authors: Ooms G. , Burgerscentrum J. M. , Kampman-Reinhartz B. E. 
Published: December 2007

Abstract
Field measurements have revealed that the pressure drop over a borehole during drilling of a slim oil well or a well with a long reach can depend significantly on the rotation speed of the drill pipe. This paper discusses analytical, numerical and experimental studies to explain this effect. Special attention is paid to the inertial forces in the liquid in the annulus caused by the rotation and eccentricity of the drill pipe. It is concluded that for large values of these inertial forces the axial pressure drop depends indeed significantly on the rotation speed of the drill pipe. A pressure drop simulator has been developed that includes this effect, and that is in good agreement with field test data.