bluuebunny/crossref_metadata_2025_split huggingface dataset:
Wellhead Safety Improvement at AL-Khafji Field
Authors: Al-Shammari F. A. , Arwansyah J. 
Published: December 2007

Abstract
For more than 30 years, AL-Khafji Joint Operations (KJO) has used experience, Knowledge and commitment to produce and process oil in safe manner. Today we continue the commitment in the ongoing wellhead safety system improvements.
Although, the oil well wellheads are secured and protected from any possibility of fire or accident, KJO intends to adopt further safety applications to meet up and fulfill the latest wellhead safety standards in oil industry.
Therefore, KJO has made an intensive development program to comply with API standards and give more protection on wellhead safety system, which can be achieved by: Replacing the old type of SSSV with new hydraulic tubing retrievable one.Replacing the old pneumatic SSV with new compact hydraulic type and control panel and re-locating the SSV from its current position down-stream the wing valve into the X-tree and up-stream the master valve.Integrating the SSV with the SSSV using control panel.Converting annular fluid flow to tubing fluid flow.
Meeting the wellhead safety standards and more, is the KJO objective and operation drive.
Formation Damage and Its Impacts on Cuttings-Injection-Well Performance: A Risk- Based Approach on Waste-Containment Assurance
Authors: Guo Q. , Geehan T. , Ullyott K. W. 
Published: December 2007

Abstract
With ever-tightening environmental regulations and the green initiatives of most operators, drilling waste disposal through downhole hydraulic fracturing often becomes the preferred waste management option. This is because the technology allows drilling wastes to be handled at the drilling site to achieve true zero discharge. However, formation damage due to solid-laden slurry injection can cause large uncertainties in injection well performance and waste containment assurance. Complicating the problems are the many formation damage mechanisms that are often difficult to model with confidence. A holistic approach based on Monte Carlo simulations has been developed for modeling formation damages and their competing contributions to injection well performance and waste containment assurance.
This paper presents a probabilistic approach to modeling and evaluating associated uncertainties, particularly geology and formation damage, and their impacts on waste containment assurance and risk assessment in cuttings reinjection operations. Probabilistic results are important in designing cuttings injection operational procedures, and risk management, and in obtaining regulatory approval. Examples are given to illustrate how to model formation damage caused by intermittent slurry injections and its impacts on waste containment. Monitoring and validation procedures are given to increase quality assurance through operational data evaluation and risk-based modeling result validation.
Innovative Cement Bulk Blending Solution Significantly Reduces Dust Emission and Provides a Safer Working Environment
Authors: Abbas R. , Metson J. , Diosse J. M. 
Published: December 2007

Abstract
Conventionally, blending cement with dry additives for the oilfield cementing applications requires several pressurized cement silos as well as multiple personnel to manage the blending process. Excessive dust emission associated with the blending process has also been an environmental concern. These conditions have classified the blending process as a relatively hazardous one for the personnel and the environment.
A dry-blending system was created to minimize the hazards related to the blending process. This efficient system has twice the capacity of a conventional bulk plant while significantly reducing the equipment and personnel involved in the blending process as well as the dust emission to the environment, offering a safer, environmentally friendlier process.
This paper will present the basic concepts of the first such system, which is operating in Abu Dhabi, UAE.
Application of Microseismic Mapping and Modeling Analysis To Understand Hydraulic Fracture Growth Behavior
Authors: Liu X. , Xu Y. , Zhao Z. , Mu L. , Liu J. , Gho Z. 
Published: December 2007

Abstract
This paper presents a detailed case history of hydraulic fracture treatments in tight oil reservoirs in remote onshore locations in China. For cases presented in this study, microseismic mapping and fracture modeling approaches were applied to understand fracture growth behavior. This paper provides a brief summary of reservoir background, but focuses on microseismic mapping as well as fracture modeling analysis. Results from fracture modeling and microseismic mapping were employed to understand post-frac performance.
Optimizing a Deepwater Subsalt Drilling Program by Evaluating Anisotropic Rock Strength Effects on Wellbore Stability and Near-Wellbore Stress Effects on the Fracture Gradient
Authors: Brehm A. , Ward C. , Bradford D. , Riddle G. 
Published: December 2007

Abstract
An understanding of geomechanics can save millions of dollars in drilling costs by reducing the likelihood of poor borehole conditions, stuck pipe and lost circulation. Basic wellbore stability modeling has been successful in the past, but may prove inadequate in some cases because the mechanism of borehole failure and characterization of fracturing is not sufficiently addressed. In these cases, a more complex geomechanical model is required. We describe an example where a complex geomechanical model was applied to address anisotropic wellbore failure due to weakly bedded rocks, and lost circulation due to equivalent annular mud weights in excess of near and far field stresses. This same model was then used to predict mud weights that should mitigate problems in future wellbores.
A New Sizing Criterion for Conformable and Nonconformable Sand Screens Based on Uniform Pore Structures
Authors: Williams C. F. , Richard B. M. , Horner D. 
Published: December 2007

Abstract
For decades the sand control industry has utilized Saucier&#8217;s criteria1 to determine gravel sizes with a corresponding screen size for gravel pack operations, while many stand-alone (or non-conformance) screen proponents have utilized other criteria such as Rodgers.2 Other variations of sizing criteria have also been used with some success.
Recent advances in the expandable screen market have led to an increasing interest in these screens over gravel packing and non-conformable screens due to the perceived simplicity in screen-sizing criteria and increased productivity. With continually increasing sand control options available to the operator, it is fitting that screen-sizing criteria match the particular application and not be universally employed across all applications.
This paper will study the behavioral performance of conformable and non-conformable screens versus gravel packs, relative to plugging resistance and percent of formation solids in the effluent stream. A test matrix was developed using several simulated formation materials from sand prone areas around the world, along with sand control media that was chosen based on the uniformity of its pores. The results indicate that the plugging resistance and percentage of solids in the effluent that passes through the sand control media differs greatly depending on the method of sand control used. The authors outline specific sizing criteria that are necessary for conformable and non-conformable screen applications.
Development of a Delayed-Chelating Cleanup Technique for Openhole Gravel-Pack Horizontal Completions Using a Reversible Invert Emulsion Drill-In System
Authors: Luyster M. R. , Patel A. D. , Ali S. A. 
Published: December 2007

Abstract
Horizontal completions in deepwater fields over the last five years have utilized gravel packing as the preferred technique for the retention of mitigating sand production in these often immature sands. Poor gravel packing, completion techniques, and/or the subsequent cleanup of deepwater, openhole completions can result in relatively high intervention costs when less than expected production is realized. Recent literature details the advantages of using an oil-based (OB) or water-based (WB) reservoir drill-in fluid (RDF) as well as the potential problems and concerns associated with both systems. The literature also discusses, in varying levels of detail, the need for cleanup of the residual filter cake, either immediately after completing the gravel pack, or with a post-intervention technique, usually coiled tubing.
The authors will discuss the development of a water-based cleanup system that was utilized in an openhole gravel-pack fluid and as the cleanup system for recent deepwater horizontal wells in a West African field. This developing technique utilizes a chelant and an amine surfactant for dispersing the residual oil-based filter cake. This cleanup is an aqueous system that has demonstrated compatibility from a reversible invert emulsion system. This system has exhibited a delay-period, whereby, the gravel-pack and subsequent isolation of the lateral section can be completed with minimal losses. To date, no post-intervention has been required to clean up serious skin damage and production histories, from these wells, have been impressive.
This paper details the laboratory development of a chelating cleanup system for a reversible RDF. Discussion of the placement of this cleanup system is included. The optimization of the chelating chemistry is discussed with respect to providing a reversal of the invert emulsion filter cake. The need for delaying the reversal is discussed with respect to the evolving completion style, thereby, providing flexibility for future designs. In addition, three field trials are presented for this novel cleanup system.
Fracture Stimulation in Waterflood Fields of Western Siberia: A Case Study of Water Prediction and Oil-Production Optimization Using Multiphase Reservoir Simulation Techniques
Authors: Guglielmo D. , Soliman M. V. , Kontarev R. , Latkin K. E. , Faizullin I. 
Published: December 2007

Abstract
Hydraulic fracturing in Western Siberia is continually evolving into larger and more aggressive fracture treatments to achieve higher conductivity than conventionally planned. At the same time some of the fields that have been waterflooded for 20 years or more for pressure maintenance, have become highly water-saturated. In the past, stimulation treatments were designed based on old log interpretations showing water saturation at original conditions and post-fracture water production was frequently under-estimated, while over-estimating oil production.
A comprehensive study was conducted into the water-flooding pattern of a Western Siberia oil field, and water-cut maps were generated to determine which areas of the field were more water-saturated. This study included a statistical analysis of the effect of various fracture parameters on the post-fracture water-cut. Also the relationship between nearby water injectors and post-fracture water production was analyzed. It was found that injectors in a NNW proximity to the fractured well contributed higher post-fracture water rate. Generally, fractures grow in this direction, which is the maximum principal stress orientation across much of the Western Siberian Basin. This paper presents and discusses the statistical approach we developed.
A new method of predicting post-fracture production involving a multi-phase reservoir simulator, was employed. The water and oil production match achieved using this simulator allowed us to re-calibrate the layer information from the original log interpretations, resulting in highly accurate production forecasts. A brief discussion of the simulator is also included in the paper.
The trend toward larger treatments and coarser proppant has (1) produced higher-conductivity fractures and (2) significantly improved production from fields in western Siberia. At the same time, the trend has created longer effective fractures and in some instances increased access to water through inter-well communication. This development has underlined the importance of understanding reservoir saturation and waterflood patterns, so that full advantage can be taken of the increased conductivity through gain in oil productivity.
These techniques of reservoir simulation and studying injector proximity were then employed in the field for candidate selection. The result has allowed fracturing to be performed in this field with greater confidence in predictability of post-fracture productivity. This paper presents the field study illustrating the developed methodology.
Lightweight Proppants: Solution for Gravel Packing Horizontal Wells Under Extreme Conditions
Authors: Pedroso C. A. , Sanches E. D. , Oliveira N. S. , Fernandes L. H. , Gomes M. , Farias R. , Mendez A. , Frata F. M. 
Published: December 2007

Abstract
When gravel packing horizontal wells, operators usually deploy conventional, and commercially available gravel pack proppants in the industry. Several jobs have been successfully completed up to date with no considerable concerns. However, under certain unfavorable conditions, a better option to gravel pack these wells is ultra-lightweight proppants.
Deepwater well, extended reach horizontals, low fracture gradients, washed out zones, and insufficient fluid returns to circulate conventional proppant in place are good examples where lighter weight proppant is needed to assure the complete packing of the open hole.
This paper summarizes the development and application of the ultra-lightweight media and associated technologies for horizontal well gravel packing. Pioneering case histories will also be reviewed from the initial wells treated. The wells were completed on a field in the Campos Basin, offshore Brazil, where the reservoirs are sandstones, highly unconsolidated and therefore require a method of sand control.
A Breakthrough Fluid Technology in Stimulation of Sandstone Reservoirs
Authors: Tuedor F. E. , Xiao Z. , Fuller M. J. , Fu D. , Salamat G. , Davies S. N. , Lecerf B. 
Published: December 2007

AbstractChallenges in sandstone acidizing still exist, although great improvements have been made in the last decade. Factors that contribute to these challenges include: multiple types of co-existing formation damage; uncertain rock mineralogy; multiple fluids and pumping stages; complex chemical reactions between fluids and formation minerals; and fast reaction kinetics at elevated temperatures. Others are: inadequate zonal coverage; limited live acid penetration; rock deconsolidation due to acid-rock interactions; acid emulsion and sludge tendencies; corrosion; and health, safety, and environmental (HSE) concerns. These factors contribute to the low success rate of sandstone acidizing treatments especially in acid-sensitive, and clay- and carbonate-rich sandstone formations at high temperatures.In this paper, we review some current practices used to address these challenges in the industry and present a new multi-pronged approach that would improve the success rate of sandstone acidizing treatments. The system requires the use of a geochemical simulator to "design for success" by selecting the safest fluid for the formation and for optimizing the fluid volumes and injection rates, and a breakthrough fluid that uses novel chemistry to simplify treatments and minimize the risk of acid-induced formation damage.Batch reaction studies indicate that the new fluid reacts more slowly with aluminosilicates than conventional mineral acids, thus preventing secondary and tertiary precipitates. Core flow tests demonstrate that the new fluid prevents the near-wellbore deconsolidation problems generally experienced with HF-based systems in high-temperature sandstone acidizing treatments. These laboratory results were corroborated with field core samples and geochemical simulations, especially with high-clay and high-carbonate sandstone formations.Extensive laboratory tests also demonstrate that the fluid results in less emulsion and sludge tendencies; lower corrosion rate to tubulars and equipment; better HSE footprint due to its almost neutral pH; and better tolerance to damage and formation uncertainties.
Optimized Frac-Pack Completion Requires an Appropriate Execution Pace
Authors: Baycroft P. D. , Webster K. P. , Mathis S. P. 
Published: December 2007

Abstract
In recent years, frac-pack completions have been proven to be a means for obtaining highly efficient completions in high-permeability, unconsolidated formations. The success of this completion technique has been attested to by it's moving into a strong lead as the most common sand control completion. Along with its wide-spread acceptance, care must be exercised to insure that we, as an industry, are not becoming too complacent concerning proper procedures.
For example, it is becoming increasingly common to "cut corners" during frac-pack execution, and eliminate pre-job field evaluations of mini-frac tests. These short cuts are typically taken in well-developed areas where it is thought little can be learned from the additional data, and the time savings are seen as significant. However, the difference in conditions as well as specific fluid characteristics from well to well, can cause less than optimal treatments being pumped if appropriate pretreatment evaluations are not performed.
This paper contains two field cases where the frac pack treatments resulted in exceptionally good production rates, low sand-face draw-downs and complete sand control. These were not straight-forward, hit and run type exercises, and both required extensive effort and forethought in terms of design, applied technology and operations. This suggests that the time spent in aligning the treatment scope with a particular reservoir needs during the execution phase of the Frac Pack completion played a significant role in the success of these completions. Therefore, when considering the use of pretreatment evaluation procedures the cost should not be viewed as "thousands of additional dollars spent" but indeed as "millions of dollars not left on the table" through optimized productivity.
Evaluation of Nonlinear Fracture Relative Permeabilities and Their Impact on Waterfrac Performance in Tight Gas Sands
Authors: Sullivan R. B. , Rushing J. A. , Bachman R. C. , Settari A. , Conway M. W. , Barree R. D. 
Published: December 2007

Abstract
This paper presents the results of a simulation study to evaluate the effects of gas-water fracture relative permeabilities on post-fracture performance for a well stimulated with a water-frac. More specifically, we investigate the effects of the fracture relative permeability curve shape on both short-term and long-term post-fracture production performance. We utilize a reservoir flow simulator coupled with a geomechanical model which allows us to account for fracture growth during the stimulation treatment and to model realistic fluid distributions in both the reservoir and fracture. We also incorporate new fracture relative (gas-water) permeability data measured in the laboratory for a range of proppant types. Unlike many previous studies that simply assume a linear shape, the new measured fracture relative permeability data are quite non-linear.
We compare short-term fracture cleanup and long-term water frac production performance using both the measured non-linear as well as hypothetical linear gas-water fracture relative permeability curves. Generally, the non-linear relative permeability data—combined with low initial absolute fracture conductivities—create very low effective fracture conductivities to gas and cause ineffective fracture cleanup. Although fractures with high absolute conductivities clean up more effectively, we still observe significant residual water saturations—even after several hundred days of production. We also observe differences in the longer-term production performance caused by residual fracture water saturations that are much higher than originally thought. Finally, we assess the effects of relative permeability curve shape on post-fracture diagnostics using pressure transient testing. Evaluation of simulated pressure buildup tests suggests the computed fracture half-lengths are essentially equal to the model inputs, but the computed effective fracture conductivities are much lower.
Encouraging Results With a New Environmentally Acceptable, Oil-Soluble Chemical for Sand Consolidation: From Laboratory Experiments to Field Application
Authors: Kotlar H. K. , Haavind F. , Springer M. , Bekkelund S. S. , Moen A. , Torsæter O. 
Published: December 2007

Abstract
The conceptual idea of chemical sand consolidation is to give the formation some additional residual strength in order to enhance the maximum sandfree rate (MSFR).
Sand production in weakly consolidated reservoirs will occur when stresses in the well/perforation tunnel walls are large enough to disrupt the binding between the individual sand grains. This will generate a plasticised layer of sand in the near well bore area. The layer will erode by the produced fluid and may be transported to the surface. The rate of erosion will depend on the residual strength of the plastified material and the fluid rate.
There is field evidence indicating a residual strength corresponding to the capillary force in water-wet sand to be sufficient in stopping or limiting the sand production substantially. Thus, only a small increase in residual strength of the plastified sand would make large contribution for enhancing the MSFR. This will have large economical implications in fields with wells controlled by MSFR.
As the criteria for strength are quite low, search for potential treatment chemicals could be done in areas completely different from the traditional chemicals used in sand consolidation. Three different chemicals have been investigated and one has been brought further for laboratory qualification and field use.
An important property is that the treatment system is oil soluble. In contrast to water soluble systems, it will not alter the relative permeability in the oil bearing zones, thereby reducing the risk of increased skin due to changes in saturation. This oil-soluble system will be beneficial in fields with low reservoir pressure. The method is employed by simple bull-heading and will have a kind of self-diverting property.
A team of engineers and scientists from different Statoil organizations were put on the job. New challenges regarding high water contamination, wells with difficult placements and zonal coverage, and a complex polymerization mechanism in the carrier fluid had to be solved. These experiences will be presented and discussed to gain valuable knowledge for future chemical sand consolidation operations.
In this paper, the experimental data and field applications will be presented. In one well, oil production was doubled as a result of the treatment.