bluuebunny/crossref_metadata_2025_split huggingface dataset:
Production Forecasting in a Limited-Data Environment: Evolving the Methodology in the Yamburgskoe Arctic Gas/Condensate Field, Russia
Authors: Shumakov Y. , Burov A. A. , Butula K. K. , Zynchenko I. A. 
Published: December 2007

Abstract
Though there are many proven ways of predicting productivity in hydraulically fractured wells in medium-permeability oil reservoirs, there is still no simple, practical production forecasting methodology for hydraulically propped fracturing stimulations for the gas and gas-condensate wells in the Western Siberian Arctic sector.
The candidate selection process, including production prediction, is at an infant development stage and is additionally hampered by the lack of, or ambiguity in, the reservoir and production data.
This is particularly true for the Yamburgskoe gas condensate field, where the wells are completed in a series of medium- and low-permeability reservoirs. Some wells cannot maintain stable production rates and have either been shut-in or are on intermittent production. Factors may include low reservoir quality, reservoir pressure, and specific production conditions. A reliable methodology for selection of candidate wells for stimulation treatments was clearly needed.
This paper describes the comprehensive methodology derived from integrated analysis of the fracturing treatments performed between 2003 and 2005 in the Yamburgskoe gas- condensate field.
The analysis revealed a series of correlations and elaborated an engineering approach that reduced the assumptions in the estimation of hydraulic fracturing efficiency, particularly for the wells that were completed but were unable to maintain stable production. Although the certainty of the final, stabilized production rate remains a challenge for the production and stimulation engineer, recent production results showed that hydraulic propped fracturing can bring many wells to economical production.
New Method To Estimate Damaged Formation Permeability With Well Testing
Authors: Zhang L. , Dusseault M. B. , Xu B. 
Published: December 2007

Abstract
Most composite solutions used in modem well test interpretation use the "step-permeability" model where the altered formations are divided into two or more concentric zones, each with constant permeability. Depending on the causes of alteration or variation, this model can deviate significantly from the real condition. A formation can be altered because of stress redistribution, drilling damage, solids co-production, mineral precipitates, and drilling mud invasion, each factor more likely to generate spatially-varying permeabilities rather than constant k zones. Experimental data confirm that a continuous permeability model is more realistic than the step permeability model.
A new semi-analytical solution with smooth radius-dependent permeability has been developed to analyze well test results from such altered formations. The altered formation is approximated as a concentric two-zone composite model: an exterior intact zone that retains the original unaltered permeability, and an interior zone where the permeability values have been altered and change as a function of radius. The permeability in this near-well zone can change continuously to the original permeability or to a different value at the boundary with the exterior zone, where there is a step-change in permeability. The choice of an increase or decrease of permeability with radius within the altered zone depends on the nature of the actual alteration. The permeability can also be simulated as a step-wise function if appropriate parameters are used; in such situations, the model collapses to conventional step-wise composite models. Other parameters such as formation porosity and compressibility of each zone can also be different, but they are assumed constant for this derivation. The new solution is derived in Laplace space, and numerical Laplace inversion is used.
Waterflooding Conformance and Water Quality: Flow Partitioning During Produced-Water Injection
Authors: Abou-Sayed A. S. , Sarfare M. D. , Zaki K. S. 
Published: December 2007

Abstract
Flow distribution plays an important role in Produced Water Re-Injection operations. This is especially true when the injection horizon contains isolated hydraulic units that are individually capable of accepting part of or the entire injection rate. The hydraulic units maybe separated by an impermeable barrier, shale, and/or have variations in the minimum horizontal stress. Under normal operating conditions fractures initiated in one or more of these units would not intersect or combine. The fracture growth becomes a coupled problem where growth in one hydraulic units is dependent on growth or retardation in other units. Retardation might be caused by solid and oil deposition in the fracture that would plug its tip and damage its faces. Plugging would decrease available fracture length for leakoff below the actual total length of the fracture. Such scenarios become difficult to control if not initially planned or designed for and can lead to undesirable effects such as inefficient sweep or uncontrolled fracture growth.
In the following discussion the design and monitoring criteria for such problems will be addressed. We will review some available tools and prominent parameters and/or variables that affect this behavior both from a time dependent and independent point of view. Particular attention will be placed on the damage mechanisms, total suspended solids (TSS) and oil in water (OIW), and their effects on altering the injection rate distribution as a progressive time dependent phenomena.
Finally, two scenarios will be presented, as practical examples of field cases where flow partitioning issues presented a particular concern as a result of inherent reservoir properties.
Perforation Damage Removal by Underbalance Surge Flow
Authors: Bolchover P. , Walton I. C. 
Published: December 2007

Abstract
In cased completions, perforations provide the essential link between the wellbore and the reservoir. Productivity of the completion is promoted by optimizing perforation characteristics such as geometry, phasing and density, but unfortunately it is restricted by the perforation damage zone— a region of low permeability material surrounding the perforation tunnel, and created by the impact of the shaped charge jet on the rock fabric.
Perforating underbalanced has become the primary means of removing perforation damage and maximizing productivity, though the mechanism by which it does so is still not very well understood. Underbalance perforating also serves to remove some or all of the comminuted sand grains that fill the perforation tunnel immediately after penetration of the rock by the shaped charge jet. Predictions of the required undeibalance to remove the damage zone or remove the comminuted fill are at best uncertain.
In this paper we describe the development of mathematical models that predict the pore pressure in the rock surrounding the perforation tunnel as the wellbore pressure drops during, for example, a dynamic underbalance operation. From this we calculate the magnitude and duration of the induced surge flow. The third stage in the analysis investigates the mechanisms through which the damage zone is removed.
As a result of these calculations we are able to predict the surge rate (and associated underbalance) required to remove the damage zone. Moreover we predict the perforation skin that results from incomplete removal of the damaged zone and for the first time we are able to determine how the skin depends on the degree and rate of underbalance.
Sustaining Conductivity
Authors: Weaver J. D. , van Batenburg D. W. , Parker M. A. , Nguyen P. D. 
Published: December 2007

Abstract
Rapid loss of fracture conductivity after hydraulic fracture stimulation has often been attributed to the migration of formation fines into proppant pack or the generation of fines derived from proppant crushing. Findings presented in this paper suggest that diagenesis-type reactions that can occur between proppant and freshly fractured rock surfaces can lead to rapid loss of proppant-pack porosity and loss of conductivity. Generation of crystalline and amorphous porosity filling minerals can occur within the proppant pack because of chemical compositional differences between the proppant and the formation, and the compaction of the proppant bed due to proppant pressure solution reactions.
This damage mechanism is applicable to all propped, fracture-stimulated wells; however, it is more significant in high temperature and high stress wells. It provides a possible explanation for the difference often observed between reservoir simulation of production after fracturing and actual production.
Studies indicate as little as 25% of the initial proppant- pack porosity may remain after only 40 days at 300°F and 6,000-psi closure stress. The rate of porosity loss can be influenced by the surface treatment of the proppant, which indicates that some control of this process may be accomplished.
Significance of this discovery has great impact on the economic life of a fracture-stimulation treatment. It affects the choice of proppant composition and post-fracture cleanup procedures, and adds an additional dimension to the appropriate laboratory determination of fracture conductivity that might be expected with the use of a particular proppant.
Case Study of Multiple Hydraulic Fracture Completion in a Subsea Horizontal Well, Campos Basin
Authors: Neumann L. F. , Fernandes P. D. , Rosolen M. A. , Rodrigues V. F. , Silva Neto J. O. , Pedroso C. A. , Mendez A. , Torres D. S. 
Published: December 2007

Abstract
This paper provides a case history of the first hydraulic fracture on a subsea horizontal well in the Quissamã formation, a low permeability limestone reservoir, in Campos Basin, Brazil.
The well was drilled in the direction of the expected fracture growth, thus evolving longitudinal fractures along the horizontal section. It is part of a research project to evaluate selective stimulation methods for subsea horizontal wells. Every single aspect since the drilling, completion, and evaluation of the well, was done with the end in mind of hydraulically fracturing it in several stages.
Hydraulically fracturing a horizontal well has become a more accepted practice in our industry. The procedures used on fracturing of vertical wells must be taken into consideration when fracturing a horizontal well, to avoid re-fracturing work. Near-wellbore (NWB) problems are usually the main cause why fracturing work are not completed. This paper describes hydraulic fracture treatments with detailed discussion on analysis of calibration tests, fluid efficiency tests, and lessons learned.
Results of the pumping work will be presented showing theory and common practices played a key role for a successful application of techniques used. Laboratory tests are presented performed with cores taken from the well itself such, as rock mechanics, proppant embedment, compactation measurements, and basic mineralogy.
Production results will be presented and compared to conventional methods used on other subsea horizontal completed wells in Campos Basin.
Expandable Sand Screens and Drilling Fluids: Laboratory Testing For Successful Field Application
Authors: Beare S. P. , Ballard T. J. 
Published: December 2007

Abstract
There are two considerations related to the drilling mud when installing sand screens: plugging of the filter media when running the screens into the wellbore, and then transporting the filtercake back through the screen when the well is produced. For compliantly expanded sand screens producing the mud filtercake is potentially more problematic as the screen is pressed into the cake during installation, and there is no annulus to allow the cake to break up and disperse before reaching the screen.
This paper describes laboratory tests for evaluating drilling fluids for use in the reservoir section when expandable sand screens are to be installed. Several examples of the results of the laboratory tests are related to well performance in the field to establish the relevance of test results. Only partial removal of the mudcake is required to give good return permeability in laboratory tests, and so field performance is predicted from comparing results with and without the screen filter medium present. This method correlates to the field, where low skins and good production have been observed with muds which give similar return permeabilities independent of screen presence in laboratory tests. Furthermore, forcing the screen into the mud filtercake during installation does not generally impede filtercake removal.
Based on these results some limitations on drilling mud formulation and conditioning for successful screen applications are established. The effect of screen presence on chemical clean-up treatments is briefly discussed, and an example is given where a failure in the field was related to poor mud conditioning prior to running the screen.
Thermal Decomposition of Thiocyanate Corrosion Inhibitors: A Potential Problem for Successful Well Completions
Authors: Ke M. , Qu Q. 
Published: December 2007

Abstract
Salts of thiocyanate (SCN-) have been widely used as corrosion inhibitors in halide-based brine completion/packer fluids for many years. When applied, they have unique characteristics over conventional amine-based inhibitors (excellent solubility in high-density brines and ability to control corrosion of brines on carbon steels and low alloy steels at high temperatures). However, SCN- may decompose at high temperatures to produce H2S or free sulfur. When SCN- thermal decomposition occurs in zinc bromide (ZnBr2)-based completion/packer fluids, H2S or byproduct of free sulfur can react with zinc ion to form zinc sulfide (ZnS) scale. The ZnS scale can cause formation damage and plug downhole tubular assemblies. Additionally, sulfide (S2-) can induce sulfide stress corrosion cracking (SSC) of high-strength and high-alloy steels under downhole environments. The presence of ZnS scale and SSC of downhole tubulars requires subsequent workovers to restore well productivity.
This paper presents the results of laboratory evaluation on thermal decomposition of SCN- inhibitors. Evaluation primarily focuses on the effect of temperatures on decomposition of thiocyanate inhibitors in ZnBr2 brines. Heat-aging tests of ZnBr2 brines inhibited with SCN- inhibitor, along with SEM/EDS techniques, were conducted to determine the decomposition temperature of SCN- and its potential to form ZnS scale. Results indicate SCN- thermally degrades at temperatures lower than those published in the literature. Evaluations of stress corrosion cracking (SCC) behavior of a high-strength and high-alloy steel in the presence of NaBr and CaBr2 brines treated with a SCN- inhibitor also are presented. These results reveal the decomposition of SCN- could cause SCC of high-strength and high-alloy steels even in chloride-free brines such as NaBr and CaBr2.
Sand Retention Testing: The More You Do, the Worse It Gets
Authors: Ballard T. J. , Beare S. P. 
Published: December 2007

Abstract
Sand retention testing is often required when selecting screen media and media size. It has also been used to define the limitations of retention for different media1. However, the results from such tests are very dependent on experimental conditions and prone to artefacts. Small and apparently innocuous changes to the test conditions can cause wide variations in results. Some of the factors affecting test results are discussed. The problems of artefacts can be overcome, at least in part, by considering trends in data rather than absolute results.
A previous paper described the performance of Dutch twill weaves (DTW) and identified a selection criteria based on particle size distributions measured by laser light scattering1. This paper extends that work to include sintered media from other premium screens and wire wrap screens. The general trend in the data from a number of tests shows good correlations between some aspects of the sand distribution and retention performance of the individual media. From these data, an aperture sizing criteria for sand screens based on laser particle size measurements is proposed, and screen selection parameters considering both retention and "plugging" performance are identified.
Influence of Rock Failure Characteristics on Sanding Behavior: Analysis of Reservoir Sandstones From the Norwegian Sea
Authors: Heiland J. C. , Flor M. E. 
Published: December 2007

Abstract
During production of hydrocarbons, the formation is subjected to increasing levels of effective stress, resulting from the reduction in pore pressure. In weak, but consolidated sandstones, this can lead to shear failure in the rock surrounding the perforations and the borehole. Sand production in weakly consolidated formations is generally assumed to be a two-step process, with the shear failure being the first step and the transport of the sand out of the perforations and up to the surface being the second step. Existing sand production prediction models have focused on predicting the onset of sanding by predicting the drawdown at which failure of the formation will start. A further development are models, which try to predict the total volume, which can be expected to be produced, by assessing the geometrical extend of the failed zone. These volumetric estimates of sand production are often based on rock mechanical models, which predict the extent of a yielded zone, using various constitutive material laws. This assumes that all material from a yielded zone will be produced as sand. Combining a model for a volumetric estimate of sand failure with a model for transport of solids in a fluid, might eventually lead to a realistic sanding rate prediction. Existing sand production prediction models tend to assume that the formation disintegrates into sand grains the moment yield or failure occurs and that these grains are taken up by the fluid flow at the time when failure occurs. However, in reality the failure-characteristics of sandstone and the pick-up of the failed material by fluid flow are a very complex process and very little research effort has been dedicated to the morphological description of rock failure.
Using an endoscope camera, it was possible to observe the failure behavior and sand transport during sanding experiments in different types of sandstones. Two different failure behaviors of perforation-sized cavities were identified in these experiments. These failure patterns resulted in very different shapes of the failed zones and during the experiments very different amounts of sand were produced and at different rates. It can be assumed that this behavior can also be found downhole and we concluded that the different failure behaviors of sandstone could be a geological reason for the different severity of sanding problems in various oilfields. Using image analysis of thin sections the different failure behavior could be linked to petrographical rock properties and a predictive model of sandstone failure characteristics was developed. This paper describes the development of the model and the application of this model to formations from an oilfield in the Norwegian Sea.
Effective Stimulation of High-Temperature Sandstone Formations in East Venezuela With a New Sandstone Acidizing System
Authors: Ali S. A. , Pardo C. W. , Xiao Z. , Tuedor F. E. , Boucher A. , Al-Harthy S. A. , Lecerf B. , Salamat G. 
Published: December 2007

Abstract
The wells in an oil field in East Venezuela have a bottomhole static temperature of approximately 230°F and varied mineralogical composition from interval to interval. Near-wellbore fines damage and carbonate scale damage have been reported in these wells. Currently, various formulations of mud acids, organics acids, and solvents are used to treat these wells with mixed results.
A novel chemical system has been developed for the stimulation of high-temperature sandstone reservoirs. By introduction of unique chemical mechanisms, the new sandstone acidizing system (1) reduces the multiple stages in traditional sandstone acidizing to one stage; (2) minimizes precipitations by delayed and stabilized reaction mechanisms; (3) provides homogeneous dissolution of formation; (4) has a much lower emulsion and sludge tendency than conventional fluids as well as lower corrosion rate; and (5) stimulates sandstone reservoirs at high-temperature by effective damage removal and further matrix dissolution.
Acid solubility, ion concentration, and mineralogical analyses indicate that the sandstone formation in this well has high content of iron-bearing minerals and a moderate content of sensitive clays. Results of core flooding tests conducted on the damaged field cores show that both mud acid and organic clay acid systems show secondary damage on the formation core sample during the acid preflush. Additionally, mud acid shows further damage after the treatment. In contrast, the new fluid system shows consistent damage removal during the treatment with the highest regained permeability. Geochemical simulations also show that more skin reduction is obtained with the new fluid than with the other conventional acid systems tested.
Optimization of a Viscoelastic Surfactant (VES) Fracturing Fluid for Application in High-Permeability Formations
Authors: Sullivan P. F. , Gadiyar B. , Morales R. H. , Holicek R. , Sorrells D. , Lee J. , Fischer D. 
Published: December 2007

Abstract
Visco-Elastic Surfactant (VES) fluids are polymer-free fluids that generate viscosities suitable for fracturing operations without the use of polymer additives. VES fluids do not form polymer filter-cake, and thus, viscous resistance of the fluid flowing through the rock matrix primarily governs fluid loss. This has historically limited the application to fracturing reservoirs with low permeabilities. A new VES fracturing fluid has been developed for use in high permeability reservoirs and successfully pumped in the Gulf of Mexico. The fluid exhibits enhanced fluid efficiency while still maintaining the high proppant pack conductivity associated with the lack of polymer damage.
In this paper, laboratory test results for the new fluid are presented along with three high-permeability case histories. The estimated reservoir permeabilities were as high as 167 mD and reservoir heights ranged from 30-90 feet. In all cases the entire propped fracture design was successfully placed.
Challenges on Completion for Productivity for Deepwater Heavy Oil
Authors: Bianco L. C. , Gabrysch A. D. , Montagna J. N. 
Published: December 2007

Abstract
The incremental demand for oil and gas is driving the industry to search and produce hydrocarbons in more challenging environments. The evolution of Drilling Technologies in recent years has allowed operators to explore high viscous oil in turbidite reservoirs, at shallow burial depth and water depths greater than 1500 m. In such environment, the reservoirs are usually formed by unconsolidated sands with low fracture gradient, high porosity and permeability, and low water saturation at low temperatures.
Although great advances have been made for open-hole completion technologies, optimizing sandface completion for productivity is a big challenge. Issues for a sub-sea well construction can be: reduced drilling fluid weight window available; special well geometries to maximize reservoir drainage; non-invasive drilling and completion fluids for well productivity; mandatory sand control; effective control on water injection and production; completion reliability and intervention requirements, thermal effects due to cold waters like hydrate formation and thermal fractures for injectors.
This paper addresses the issues related to well construction in such environment and presents recent developments for well completion design such as: new approach for sand control system selection for heavy oil that excludes sand but allows fines to pass; minimization of the pressure drop through the sand control system; well segmentation to correct the oil influx profile, improving reservoir drainage, and giving selectivity and control of water production.