bluuebunny/crossref_metadata_2025_split huggingface dataset:
Increasing Reservoir Contact by Combining Mechanical Diversion and Unique Stimulation Chemistry
Authors: Veillette Christian P. , Cuzella Jerome J. , Mueller Fred A. , Loayza Michael P. , Malaver Rafael , Abaza Bayan , Gurmen M. Nihat 
Published: January 2009

Abstract
The Edwards Limestone in South Texas often requires stimulation to be commercially productive. The relatively low permeability, high Young's Modulus, presence of natural fractures, minimal stress barriers to control height growth, and formation temperatures up to 375°F provide a challenging environment for a successful stimulation. Conventional stimulation approaches using acid fracturing and proppant fracturing techniques often have resulted in less than optimal effective etched or propped fracture half lengths, respectively.
Horizontal openhole completions have increased the potential reservoir contact to the wellbore, but are not effective without stimulation. Achieving the diversion along the horizontal wellbore that is required to effectively treat the entire interval proved difficult using conventional diversion techniques with particulate and chemical diversion. Furthermore, the difficulty in achieving sufficient fracture width limits the proppant concentration that can be pumped into the formation. Acid fracturing was a desirable stimulation technique, but because of the high reservoir temperature and associated high acid spending rate, it was difficult to achieve a long effective etched half length with acid fracturing.
A unique approach was developed by combining a novel diversion technique with a new stimulation treatment. The diversion technique enables mechanical isolation of the openhole completion during the stimulation treatments. The mechanical diversion system also facilitates efficient pumping of multiple stimulation treatments, resulting in increased reservoir contact to the wellbore. The new stimulation treatment uses a unique lightweight (1.25 SG) proppant-like material that is pumped into the well as an inert substance. The product hydrolyzes only after the solid particles are in the reservoir for an amount of time at temperature. This enables the fracture etching process to occur during shut-in and flowback of the well thus solving the problem of creating long effective etched fracture half lengths with acid. The combination of these two techniques has enabled a much larger stimulated reservoir contact to the wellbore in the Edwards Limestone in South Texas, which leads to improved production.
Quantifying Transient Effects in Altered-Stress Refracturing of Vertical Wells
Authors: Roussel Nicolas Patrick , Sharma Mukul Mani 
Published: January 2009

Abstract
The production or injection of fluids in reservoirs results in a redistribution of stresses. In this paper, the extent of stress reorientation has been calculated for fractured production and injection wells and the results have been analyzed for their impact on refracturing operations. Rules of thumb and charts have been provided to help candidate well selection for refracturing based on the study.
For previously fractured wells, it is possible to create a secondary fracture that is perpendicular to the first fracture. The secondary orthogonal fracture can be created only within a certain time-window that in turn depends on the reservoir properties. Conditions leading to orthogonal secondary fractures in different kinds of reservoirs (oil, gas and tight gas reservoirs) have been analyzed to establish some rules of thumb. The effects of the layers bounding the pay zone and of permeability heterogeneity and anisotropy on stress reorientation are also discussed.
Our results, for the first time, allow us to quantify the phenomenon of orthogonal secondary fracturing around fractured production wells by calculating the extent of the stress reversal region as a function of time. The results of our model are shown to agree qualitatively with field observations obtained from micro-seismic measurements. The model presented in the study helps to demystify the concept of refracturing and provides a quantitative estimate of the time-window for refracturing as a function of dimensionless parameters. The final result demonstrates the potential of the model to increase the reservoir sweep in unconventional reservoirs for which the optimum time-window for refracturing is of the order of months to years. The conclusions of this study are useful for the design of refracturing operations and candidate well selection.
Impact of Capillary Suction on Fracture Face Skin Evolution in Waterblocked Wells
Authors: Mahadevan Jagan , Le Duc , Hoang Hai 
Published: January 2009

Abstract
Hydraulic fracturing operations, carried out by injecting large volumes of water, cause invasion of the injected water into the formation and trapping due to capillarity. This invasion, also termed as water blocking, can cause a reduction in the gas well productivity by reducing the relative permeability of gas with respect to water. The flow of gas toward the wellbore/fracture during production well will result in the removal of water block through viscous displacement as well as evaporation, which occurs primarily due to gas expansion over long period of time. However, recent observations from field show that the productivity of hydraulically fractured wells improves after a period of shut-in leading to a speculation as to whether capillary suction is responsible for the clean-up of water block which eventually leads to productivity improvement. In this work, we solve for the gas relative permeability improvement of the invaded zone of a fractured well accounting for both evaporation and capillary suction. The conservation equations, for both water and gas, are solved numerically to obtain water saturations and gas relative permeability in the damaged zone. Simulations, of gas relative permeability with time, show that when water invasion depth is small, capillary imbibition is the dominant clean up mechanism. For larger depth of invasion, both capillary imbibition and evaporation contribute to the clean-up of water-block leading to the improvement of gas relative permeability in the invaded region. However, when the viscosity of invaded liquid is high, and the liquid mobility is reduced, capillary imbibition maybe negligible and evaporation becomes the dominant clean up mechanism. Our results show that the inclusion of capillary driven flows is important in the prediction of gas well deliverability calculations when water blocking occurs. This study presents a model, combining both viscous removal and evaporation, to calculate the evolution of fracture face skin due to progressive removal of waterblocks and hence well productivity under field conditions.
Overcoming Excessive Fluid Loss in Tip-Screen-Out Stimulations of Depleted, High-Permeability Reservoirs Using a New-Generation Viscoelastic Fluid: Successful Case Histories in West Venezuela
Authors: Parra P. , Miquilena E. , Sánchez A. , Peña A. , Garcia A. , Millán M. 
Published: January 2009

Abstract
Tip-Screen-Out (TSO) stimulations of high permeability reservoirs have been performed in North and South America (i.e., USA, Venezuela, Trinidad, Colombia), in Africa (i.e., Nigeria, Gabon, Congo, Ivory Coast, Cameroon), in Europe (i.e., North Sea, Italy), in the Middle East (i.e., Saudi Arabia) and in Asia (i.e., Indonesia). As reservoirs in these regions mature, fluid loss control and fluid-inflicted formation damage become increasingly important and conflicting issues. On one hand, the use of classic fluid loss additives and/or fluids with good fluid loss control characteristics (i.e., polymer-based fluids) is typically associated with well production impairment because of residues left in the formation. On the other hand, fluids that are considered nondamaging, such as viscoelastic surfactant (VES) fluid systems, typically exhibit limited fluid loss control capabilities, making fluid efficiencies low and proppant placement inadequate. Nondamaging fluids are needed that can deliver adequate fluid loss control under severe reservoir conditions (i.e., upon concomitant occurrence of high permeabilities and low reservoir pressures).
Bachaquero field located in Lake Maracaibo, Venezuela, and managed by Petróleos de Venezuela (PDVSA) is a critical example of these depleted, high-permeability reservoirs. Permeabilities in this field range from 100 mD to 1 D. The average pressure gradient is 0.2 psi/ft. VES fluids typically have been used to hydraulically fracture reservoirs in this field. However, fluid efficiencies observed in recent jobs were as low as 2% and proper proppant placement under these conditions was no longer possible.
In our study, we consider relevant technical aspects and case histories in a systematic study that is aimed at assessing the usefulness of a new-generation VES fluid tailored for high-permeability reservoirs to address low fluid efficiencies in the Bachaquero field. The study encompassed adjustments in fluid formulation to ensure compatibility with local production water and crude oils, specific engineering and quality assurance/quality control guidelines, and field trials in 10 wells, followed by quantification of the enhancements achieved in fluid efficiency and well production.
Field tests showed that fluid efficiencies increased by up to 325%, as compared to conventional VES fluids previously used in this field. Production expectations were exceeded in all tested wells by an average of 65%. The study concluded that the new-generation VES fluid is suitable for use in the Lake Maracaibo area and it has been adopted as the fluid of choice for Bachaquero field. What we learned from this successful campaign is valuable when assessing stimulation strategies for mature high-permeability reservoirs worldwide.
Seismic Velocity Model Calibration Using Dual Monitoring Well Data
Authors: Maxwell S. C. , Zimmer U. , Wolfe J. 
Published: January 2009

Abstract
A hydraulic fracture stimulation was monitored with borehole geophone arrays deployed in two observation wells. The resulting microseismic images showed that the first horizontal well stimulation was characterized by a diffuse cloud of microseismic events, and the production log indicated roughly uniform production along the length of the well. The second horizontal well stimulation was characterized by clustered microseisms, and the production log indicated significant production from the intersection of pre-existing fractures with the well. The resulting case study allowed a comparison of accuracies between a single observation well and two observation wells. A comparison was also made of the microseismic event location accuracy resulting from of the different configurations of observation wells. The dual well observations provide an opportunity for enhanced velocity model validation in addition to enhanced source imaging techniques to provide additional information about the fracture geometry.
Acid–Etched Channels in Heterogeneous Carbonates — A Newly Discovered Mechanism for Creating Acid Fracture Conductivity
Authors: Mou Jianye , Zhu D. , Hill A. D. 
Published: January 2009

Abstract
In the acid fracturing process, the fracture conductivity created by acid etching of the fracture walls is due to the surface roughness created by the acid's non-uniform dissolution of the fracture surfaces. The acid fracture conductivity is dependent on surface etching patterns, which are determined by permeability and mineralogy distributions. That is, the spatial distribution of fracture roughness affects the fracture conductivity, which cannot be considered in laboratory measurements of acid fracture conductivity which use core samples that are too small to observe such macro-scale heterogeneities, nor in typical acid fracture simulations, in which the grid block size is much larger than the scale of local heterogeneities.
An accurate prediction of acid fracture conductivity necessitates the detailed description of the acid etching profiles on the fracture surfaces, which depend on acid transport in the fracture, leakoff due to local permeability, and acid/rock reactions. In this paper, we developed a three dimensional intermediate-scale acid fracture model with grid block sizes small enough and total dimensions large enough to capture local and macro-scale heterogeneity characteristics. The model predicts the pressure field, the flow field, acid concentration profiles, and fracture surface profiles as functions of acid injection volume. In the model, we use a front-fixing method (Crank, 1984) to handle the irregular, moving boundaries in numerical simulation. Spatially correlated permeability and mineralogy distributions were generated by using a semi-variogram model.
The model was validated by comparing simulation results with experimental results from an acid fracture conductivity cell. With the model, we analyzed the relationship among fracture surface etching patterns, conductivities, and the distributions of permeability and mineralogy. We also illustrated the formation characteristics necessary for acid to create channel-caused high acid fracture conductivity. We found that a fracture segment with channels extending from the inlet to the outlet of the segment has high conductivity because fluid flow in deep channels needs a very small pressure drop. Such long and highly conductive channels can be created by acids if the formation has heterogeneities in either permeability or mineralogy, or both, with strong correlation strength in the main flow direction, which is the case in laminated formations.
Modeling Fracture Fluid Cleanup in Tight Gas Wells
Authors: Wang John Yilin , Holditch Stephen A. , McVay Duane A. 
Published: January 2009

ABSTRACT
On occasion, a hydraulically fractured tight gas well does not perform up to its potential because of slow or incomplete fracture fluid cleanup. A number of papers have been written to address individual factors related to fracture fluid cleanup, but there are still many unanswered questions as to which factors mostly affect gas production from such wells. Numerical reservoir simulation is one of the best methods to study the fracture fluid cleanup problem. Continuing from our previous publication (SPE 117444) on the impact of gel damage on fracture cleanup, we used reservoir simulation to analyze systematically the factors that affect fracture fluid cleanup and gas recovery from tight gas wells.
We first developed a comprehensive data set for typical tight gas reservoirs, and then ran single-phase flow cases for each reservoir and fracture scenario to establish the idealized base-case gas recovery. We then systematically evaluated the following factors: multiphase gas and water flow, proppant crushing, polymer filter cake, and finally yield stress of concentrated gel in the fracture. The gel in the fracture is concentrated due to fluid leakoff during the fracture treatment. We evaluated these factors additively in the order listed. We found that the most important factor that reduces fracture fluid cleanup and gas recovery is the gel strength of the fluid that remains in the fracture at the end of the treatment.
This paper illustrates the complexity of the fracture fluid cleanup problem and points out the need to use reservoir simulation and to include all the pertinent factors in order to rigorously model fracture fluid cleanup. The procedures presented can provide a useful, systematic guide to engineers in conducting a numerical simulation study of fracture fluid cleanup.
Fracture Containment in Soft Sands by Permeability or Strength Contrasts
Authors: de Pater C. J. , Dong Y. 
Published: January 2009

Abstract
We have conducted laboratory tests to investigate the containment of hydraulic fractures in unconsolidated, layered formations. We varied both permeability and strength of the layers in the samples. The fracture evolution was observed with X-Ray CT scanning and by excavating the sample after the test.
We found that permeability is the dominant factor in containment, if the stress contrast is small. With a factor of three to four between the permeability of the two layers there is a strong tendency for the fracture to propagate in the low permeability layer. Difference in strength is much less important for containment.
A numerical fracture propagation model described the sand as an elasto-plastic material with parameters obtained from triaxial tests and used a simplified leak-off description of the cross-linked gel. The results agree qualitatively with the tests.
Barnett Shale Refracture Stimulations Using a Novel Diversion Technique
Authors: Potapenko D. I. , Tinkham S. K. , Lecerf B. , Fredd C. N. , Samuelson M. L. , Gillard M. R. , Le Calvez J. H. , Daniels J. L. 
Published: January 2009

Abstract
Gas production from the unconventional Barnett Shale reservoir now exceeds 3 Bcf/d, which is more than 5% of total U.S. dry gas production. Typically Barnett Shale wells exhibit a rapid production decline following the initial hydraulic fracture stimulation treatment, so that, within 5 years, an operator is normally faced with a well producing below its economic threshold. To keep up with current gas demand, operators have moved to an aggressive horizontal drilling and completion program. Additionally, in an effort to increase the productivity of existing wells and book additional reserves at reduced cost, operators have restimulated their older vertical wells, with demonstrable success. This success is providing compelling opportunities to enhance refracture treatment coverage by targeting bypassed and ineffectively stimulated zones in additional vertical wells and even some horizontal wells. Because of the heterogeneous nature of this unconventional gas reservoir, the restimulation of horizontal wells is problematic, and operators have demonstrated limited success using current stimulation techniques.
This paper describes a new fracture diversion technique particularly adapted for horizontal well refracture stimulation. During the treatment, a fracture diversion system (FDS) is used to create a temporary bridge within the active fracture networks. That results in differential pressure increase and causes treatment redirection to understimulated intervals along the lateral. This technique enables both fracture diversion without mechanical intervention and, when enhanced with microseismic monitoring, real-time optimization of the fracturing treatment.
Refracture stimulation case studies are presented in which this novel diversion technique is successfully applied to horizontal Barnett Shale wells. This paper demonstrates how real-time hydraulic fracture monitoring has enabled operators to make informed decisions that influence fracture geometry, increase lateral coverage, and improve gas recovery. To date, more than 20 fracture diversion designs have been successfully placed. The trial wells have included both cemented and uncemented completions, with drilled azimuths selected to encourage either transverse or longitudinal fracture fairway development. With a continuing optimization of the described refracturing technique, these FDS designs and placement strategies have evolved to the point where they are consistently exhibiting fracture diversion as evidenced by movement of microseismic activity and improved lateral coverage.
While this engineered fracture diversion technique is ideally suited for re-fracture stimulations, it is also applicable for stimulation of new wells where the technique enables stimulation of larger wellbore intervals when used in the same fashion as for re-fracture stimulation applications.
Fiber-Laden Fluid—Applied Solution for Addressing Multiple Challenges of Hydraulic Fracturing in Western Siberia
Authors: Sitdikov S. , Serdyuk A. , Nikitin A. , Yudin A. , Mullen K. , Oussoltsev D. , Butula K. K. 
Published: January 2009

Abstract
This paper describes successful implementation of degradable fiber-laden fluids for hydraulic fracturing in one of the largest oilfield in Western Siberia. Placement advantage of fiber-assisted fluid already becomes obvious after initial campaign of four fracturing treatments. It demonstrated good proppant carrying capabilities and allowed decrease of polymer load without increasing risk of premature screenout. Fibers proved to be reliable for successful placement of 10/14-mesh size Intermediate Strength Proppants (ISP) at concentration up to 1000 kgPA and higher with only 3.0 kg/m3 (25lb/1000gal) guar polymer loading, a feat previously only achievable with 3.6-4.2 kg/m3 (30-35lb/1000gal) gel loading in similar geological conditions.
In addition to reducing damage with lower polymer concentrations, other advantages of degradable fiber usage were anticipated to be proven after proppant fractures geometries and production parameters (including PI and Jd) evaluation. Analyses of the fracturing treatments have been performed based on bottomhole pressure gauges data and well-supported with direct fracture geometry estimation obtained by using differential cased hole sonic anisotropy measurements. As it is common for most formations in Western Siberia to have high degree of lamination and multiple shaly layers inside producing zone, pilot well-candidates for the project were specifically selected to have complex geology including several layers of sandstones and shaly strikes. This requires the fracture to intersect layers of sandstone and provide optimum connection for hydrocarbons flow to the wellbore, by evenly distributing proppant throughout the height of the fracture. Thus, degradable fiber-assisted fluid must be utilized, as conventional fracturing fluids may not suspend proppant for required time period and proppant settling during fracture closure results in considerable part of net pay being under stimulated.
The laboratory testing on large size ISP proppant suspension by degradable fiber in viscous fluids was performed for this project and described in the paper.
Western Siberia field and degradable fiber-laden fluid provided a good example of how one solution may be applied for various challenges of hydraulic fracturing optimization. This research will present a comprehensive story supported by technical analyses.
Water as a political good: revisiting the relationship between politics and service provision
Authors: Schwartz Klaas , Schouten Marco 
Published: January 2009

Because water services are a private good, a merit good, an economic good and subject to market failure, the provision of water services features prominently on the political agenda in many countries, essentially making it a “political good”. Being a political good, the majority of water supply and sanitation services are still provided by public sector organizations. These public utilities have often provided very poor services and one of the main causes of the failure to provide adequate services is the political involvement in the sector. As a result, many professionals have called for the stringent separation of the political realm from service provision.
In this article it is argued that the realities of the water services sector are such that a stringent separation of the political realm from the management of the service provider is unrealistic, if not naive. Moreover, the article seeks to present a more nuanced view of the relationship between politics and service provision by arguing that service providers, who have improved services significantly, have been able to do so because of support from the political realm, which extended well beyond the activities of making policy.