bluuebunny/crossref_metadata_2025 huggingface dataset:
The conservation status of the tuco-tucos, genus Ctenomys (Rodentia: Ctenomyidae), in southern Brazil
Authors: Fernandes FA. , Fernández-Stolz GP. , Lopes CM. , Freitas TRO.
Published: February 2008

The goal of conservation biology should be related to the preservation of species and also to the evolutionary and ecological processes that were responsible to form them and that are still acting. We review the conservation status of the species of tuco-tuco (Ctenomys torquatus, C. lami, C. minutus, and C. flamarioni) from southern Brazil, and relate these data to the geological history of a particular area in that region, the Coastal Plain of the States of Rio Grande do Sul and Santa Catarina. The implications of the data on these species from the Southeastern Brazil are also discussed in relation to the evolution and risk of extinction of these subterranean rodents.
Population structuring of the endemic black-cheeked gnateater, Conopophaga melanops melanops (Vieillot, 1818) (Aves, Conopophagidae), in the Brazilian Atlantic Forest
Authors: Lunardi VO. , Francisco MR. , Galetti Jr. PM.
Published: February 2008

Randomly amplified polymorphic DNA (RAPD) markers were used to analyze genetic differentiation among three populations of the endemic Black-cheeked Gnateater (Conopophaga melanops melanops) within a larger pristine reminiscent of the Brazilian Atlantic Forest. Analyses of molecular variance (AMOVA) (phiST = 0.13149, P < 0.0001) and the nonparametric test for homogeneity of the molecular variance (HOMOVA) (B = 0.32337; P = 0.0019) showed a statistically significant genetic divergence among the three Black-cheeked Gnateater populations in a continuous transect of 250 km. Some hypothetic explanations for these results are the sedentary nature of the species and the historical isolation of the populations in refuges during the Pleistocene. The present results suggest that the local populations were naturally differentiated along the entire original range before the recent process of massive deforestation.
Conservation strategies for Arapaima gigas (Schinz, 1822) and the Amazonian várzea ecosystem
Authors: Hrbek T. , Crossa M. , Farias IP.
Published: February 2008

In the present study we report a spatial autocorrelation analysis of molecular data obtained for Arapaima gigas, and the implication of this study for conservation and management. Arapaima is an important, but critically over-exploited giant food fish of the Amazonian várzea. Analysis of 14 variable microsatellite loci and 2,347 bp of mtDNA from 126 individuals sampled in seven localities within the Amazon basin suggests that Arapaima forms a continuous population with extensive genetic exchange among localities. Weak effect of isolation-by-distance is observed in microsatellite data, but not in mtDNA data. Spatial autocorrelation analysis of genetic and geographic data suggests that genetic exchange is significantly restricted at distances greater than 2,500 km. We recommend implementing a source-sink metapopulation management and conservation model by proposing replicate high quality várzea reserves in the upper, central, and lower Amazon basin. This conservation strategy would: 1) preserve all of the current genetic diversity of Arapaima; 2) create a set of reserves to supply immigrants for locally depleted populations; 3) preserve core várzea areas in the Amazon basin on which many other species depend. We stress that conservation strategies should not only preserve current genetic diversity, but also the evolutionary processes which have generated the observed patterns.
Structural chromosome polymorphism in a Pimelodus maculatus La Cepède, 1803 population (Siluriformes, Pimelodidae) from the Paranapanema River basin, PR, Brazil
Authors: Mazzuchelli J. , Swarça AC. , Dias AL.
Published: February 2008

In the present cytogenetic study of Pimelodus maculatus, 13 specimens (8 males and 5 females) from the Congonhas Stream in Paraná State, Brazil, were examined using conventional staining. All of them showed a karyotype of 2n = 56, with a chromosome distribution of 20m + 20sm + 10st + 6a. However, four individuals (2 males and 2 females) were found to have a variant karyotype (cytotype) with two heteromorphic chromosomes in the group of submetacentric chromosomes - one of them corresponds to the second largest chromosome of this group and the other is a chromosome of small size. This variation suggests the existence of a structural polymorphism in the studied population.
Chromosome polymorphism and complements in populations of Girardia species (Platyhelminthes, Tricladida, Paludicola) from southern Brazil
Authors: Benya E. , Leal-Zanchet AM. , Santos WH. , Hauser J. , Erdtmann B.
Published: February 2008

The karyotypes of four species of freshwater triclads of the genus Girardia (Platyhelminthes), i.e. G. schubarti, G. tigrina, G. anderlani, and G. biapertura, from populations of different localities of the Rio Grande do Sul State, in southern Brazil, were analyzed. The karyotype of G. biapertura is presented for the first time. Three basic complements of 4, 8, and 9 chromosomes were found. Diploids, triploids, or mixoploids (2n/3n) specimens were frequently detected in these populations. The basic chromosomal complement of n = 9 was verified in two different species (G. biapertura and G. anderlani), presenting a large acrocentric chromosome which is rare in the family Dugesiidae. An intra and interspecific chromosomal variability was also detected and its evolutionary implications are discussed.
Intra and inter populational genetic variability in Maytenus ilicifolia Mart. ex Reiss. 1861, through RAPD markers
Authors: Mossi AJ. , Cansian RL. , Leontiev-Orlov O. , Zanin EM. , Oliveira CH. , Cechet ML. , Carvalho AZ. , Echeverrigaray S.
Published: February 2008

Maytenus ilicifolia is a medicinal plant largely used in the South Brazilian folk medicine. The aim of this study was to quantify the intra and inter populational genetic variability in three populations of M. ilicifolia, focusing on the genetic conservation of this species, which has been threatened by anthropic action. RAPD (Random Amplified Polymorphic DNA) markers were used to analyze 30 plants of each of the three populations collected in the Alto Uruguai Gaúcho region. Fourteen selected primers generated a total of 158 bands, 71.5% of which were polymorphic. The comparison of Jaccard’s distances showed that the intra populational variation was higher than the inter populational variability, and cluster analysis allowed the separation of the three populations. Just 7.6% of the bands were specific of at least two populations. Data indicate that the analyzed M. ilicifolia populations represent a single genetic pool, and therefore any of the population thoroughly can represent the overall genetic variability of the species in the sampled region.
Alterações difusas da traquéia: aspectos na tomografia computadorizada
Authors: Marchiori Edson , Pozes Aline Serfaty , Souza Junior Arthur Soares , Escuissato Dante Luiz , Irion Klaus Loureiro , Araujo Neto César de , Barillo Jorge Luiz , Souza Carolina Althoff , Zanetti Gláucia
Published: February 2008

O objetivo deste ensaio pictórico foi apresentar as principais alterações tomográficas observadas em doenças que acometem a traquéia de forma difusa. As doenças estudadas foram amiloidose, traqueobroncopatia osteocondroplástica, traqueobroncomegalia, papilomatose laringo-traqueo-brônquica, linfoma, neurofibromatose, policondrite recidivante, granulomatose de Wegener, tuberculose, paracoccidioidomicose e traqueobroncomalácia. O principal aspecto observado na tomografia computadorizada foi o espessamento das paredes traqueais, com ou sem nodulações, calcificações parietais ou comprometimento da parede posterior. Embora a tomografia computadorizada permita a detecção e a caracterização das doenças das vias aéreas centrais, e a correlação com os dados clínicos reduza as possibilidades diagnósticas, a broncoscopia com biópsia continua sendo o procedimento mais importante no diagnóstico das lesões difusas da traquéia.
Modeling of Permeability Impairment by Invasion of Solid Suspension During Waterflooding in Heterogeneous Porous Media
Authors: Moghadasi Jamshid
Published: February 2008

Waterflooding is one of the economically viable techniques for recovery of additional oil from mature fields. However, the brine used for it frequently contains suspended fine particles, which can deposit over the injection formation face and inside the adjacent wellbore formation to reduce the injectivity of the Waterflooding wells. In the state-of-the-art approaches of formation damage modeling by solid invasion, the heterogeneities of porous media should be considered. Sandstone invariably have small-scale heterogeneities, that may cause the effect of injected fluid carrying suspended particles on permeability alteration, to differ from what is predicted by a model based on a homogeneous formation.

The objective of this paper is to develop a mathematical model according to an overall mass balance, to investigate the effect of local heterogeneity of rock properties on permeability impairment by movement and deposition of solid particles instead of assuming a uniform porosity/permeability distribution as was used in the pervious models presented in the literature. The heterogeneous original porosity has been generated using standard geostatistical techniques.
Prediction of Influx Rate and Volume for Planning UBD Horizontal Wells To Reduce Formation Damage
Authors: Guo Boyun , Feng Yin , Ghalambor Ali
Published: February 2008

Underbalanced drilling (UBD) has been widely used as a means of reducing formation damage during drilling. The benefit of reduced formation damage results from the fact that the borehole pressure is intentionally maintained to be lower than formation pore pressure during drilling the pay zone.

UBD operations require additional surface equipment such as separators and reserve tanks to process and store the produced reservoir fluids. Selection of separators and reserve tanks for UBD involves using a method to predict reservoir fluid inflow rate and volume. Such a method is not available in the literature for UBD horizontal wells. This study filled the gap.

In this study, we derived an equation for pressure distribution in the borehole by rigorously coupling formation inflow and borehole hydraulics. A simple function for fluid influx rate distribution in the borehole was then developed. Fluid influx rate is predicted as a function of horizontal borehole length, which is time-dependent. The predicted fluid influx rate at the total depth is used for sizing separators. The total influx volume is predicted by integrating the influx rate over the total time for horizontal drilling. The predicted total influx volume is used for determining the required capacity of reserve tanks. A work procedure was developed for generating fluid inflow rate and influx volume profiles. Application of the procedure is illustrated in solving an example problem. This paper presents drilling engineers a mathematical tool that can be used for sizing separators and reserve tanks during horizontal UBD planning.
New Viscoelastic Surfactant Fracturing Fluids Now Compatible With CO2 Drastically Improve Gas Production in Rockies
Authors: Arias R. E. , Nadezhdin S. V. , Hughes K. , Santos N.
Published: February 2008

Historically, carbon dioxide (CO2)-foamed fracturing fluids were used to stimulate wells in the Waltman field in Wyoming—due to the low formation permeability and rock properties—and have been proven effective, but still not perfect. Limitations on the amount of proppant placed near water zones and formation damage from polymer residuals were the main drawbacks. A never ending quest for efficiency and higher production rates called for different options. One of those options was the recently developed CO2 viscoelastic surfactant (VES) fluid system. It has recently been employed to eliminate the disadvantages of the traditional polymer-based fluid. This VES-CO2 fluid system combines the benefits of viscoelastic surfactant-based fluid—such as low formation damage, superior proppant transport, and low friction pressures—with carbon dioxide advantages of enhanced cleanup and better hydrostatic pressure. This fluid was recently selected for the fracturing treatments on three wells. Initial production from these wells was observed in the range of 5 to 7 MMcf/D, significantly greater than neighboring wells' gas rates of 2 MMcf/D stimulated with polymer-based fluid.
Modeling Air and Water Perforator Swell for Better Risk Management
Authors: Han C. , Du Michael H. , Walton Ian C.
Published: February 2008

A detonated shaped charge fired from a perforating string or perforating gun will not only perforate its targets, but also possibly cause excessive damage or swell to its carrier. Comprehensive understanding of the post-perforating conditions of the perforator or perforator system is required if such damage and potential retrievability risks are to be avoided. In practice, the perforating design engineers do not have a well-established analytical tool to help them understand post-perforating behavior of perforators. They have to rely on their own experiences and previous perforating histories to roughly estimate the swell or damage conditions of similar perforators.

In this paper we analyze the failure modes of continuously phased perforators for both gas well and oilwell applications. Important factors concerning carrier serviceability are discussed. A method based on energy conservation is used to establish a swell model to predict the post-detonation conditions of the perforator. The model takes the total expendable energy from the explosives into account, relates it to the energy consumed by the functional and nonfunctional processes, and describes the relationship of energy distribution among them. A criterion is proposed to establish the serviceability of the perforators.

Analytical results from the model are compared with the data collected from surface tests. The results indicate that the model can reasonably predict the perforator swell and damage after detonation, and as such will be a useful tool that shortens the required time to develop future perforators.
New Effective Stress Law for Predicting Perforation Depth at Downhole Conditions
Authors: Grove B. , Heiland J. , Walton I. , Atwood D.
Published: February 2008

For natural completions, well productivity is proportional to the depth of the perforation tunnels. Perforation depth, in turn, is generally inversely related to the formation effective stress. Accurate productivity modeling, therefore, requires accurate knowledge of the relationship between the downhole stress environment and perforation depth.

A comprehensive experimental effort was recently conducted to evaluate the penetration performance of shaped charges into stressed Berea sandstone cores. Rock confining stress (σc) and pore fluid pressure (Pp) were varied from ambient to 10,000 psi, to simulate a range of downhole stress environments. This current work featured a broader and more systematic investigation of the influence of pore pressure than previous studies.

Our experiments yielded the expected inverse correlation between penetration depth and effective stress (σeff). However, the data suggest a new definition of effective stress. Historically, the perforating community has defined σeff = σc - Pp, but a new treatment (σeff = σc - aPp; a=0.5) better fits present data. Furthermore, this new effective stress law better fits published historical penetration results. Pore pressure's influence on penetration depth is therefore weaker than previously thought; for a given confining stress, increasing pore pressure does increase penetration, but to a lesser extent than conventional models would indicate. The present work suggests that all shaped charges would be similarly affected.

These findings are relevant to penetration modeling, and in turn to well productivity modeling and prediction. Further implications are to laboratory testing, regarding scaling of parameters to accurately simulate field conditions.

This work culminates an initial application of combined penetration mechanics and geomechanics analyses to the investigation of shaped charge penetration into geologic materials. Future work will address different rock types, additional poroelastic quantities, and dynamic effects as they contribute to pressure-induced strengthening of reservoir rock.
Determination of Optimum Perforation Design and Sanding Propensity in Long Horizontal Wells Based on Modified RP 19B Section IV Tests and Numerical Sand Prediction
Authors: Andrews J. S. , Bjørkesett H. , Djurhuus J. , Walton I. C. , Atwood D. C. , Heiland J. , Grove B. , Langseth B.
Published: February 2008

Gjøa is an oil and gas field located off the Norwegian Coast that is due to be developed with subsea infrastructure tied back to a floating production facility. Nine horizontal oil producers and four S-shaped gas producers are planned and all will require some form of sand prevention. Extensive rock mechanical work using Statoil's finite element modeling method suggests that oriented perforations can prevent sand production in the horizontal wells. This was offered as an alternative to mechanical sand control in the long horizontal wells due to traverse several shale and sand bodies of varying quality.

Perforation tunnels with optimal "structural" stability for the given inherent material strength of the formation rock can be achieved by targeting perforations in the most stable direction with respect to the in-situ stress field. For high angle wells this normally equates to shooting in the vertical plane through the well path. Over a decade of production experience with this technique on the Norwegian Continental Shelf (NCS) confirms that oriented perforating can be a good sand prevention measure in suitable fields. Despite this track record and the rock mechanical analysis performed, the Gjøa project team wanted to conduct laboratory tests to confirm its applicability and also to optimize perforating parameters. An extensive laboratory test program was conducted on representative core and outcrop material. Five modified API RP 19B Section IV tests were performed to assess the influence of static and dynamic wellbore pressure conditions and wellbore fluid on perforation clean-up and PI. In addition, two tests were conducted on field core material in order to evaluate the sanding propensity of oriented perforations under conditions approximating those predicted during pressure depletion. The laboratory conditions required to induce sand production were quite extreme and vastly exceed the production scenario for the planned oil wells in the field. However, the cell geometry, boundary conditions and stress field in these experiments are not truly representative of the in-situ conditions around a true perforation in a well. In order to translate the sanding results into a conclusion relating to the validity of oriented perforating for the field, a finite element model was built to reproduce the lab conditions. This model correctly predicted the conditions required for sand failure as observed in the lab. This agreement provided validation of the operator's general sand prediction methodology and gave good confidence in the earlier rock mechanical predictions made for the field.
Effect of Basic Parameters on the Viscosity of Synthetic-Based Drilling Fluids
Authors: Ghalambor A. , Ashrafizadeh S. N. , Nasiri M.
Published: February 2008

In this study the effect of interactions among the ingredients of synthetic-based fluids (SBFs) on the rheology of the fluid at ambient temperature was investigated. It has been also attempted that through examination on the important variables affecting those interactions, the mechanism of viscosity building in SBFs be identified. Rheology measurements along with the microscopic observations from the invert emulsion structure of the SBFs can be utilized for such an examination. Viscosity building in the SBFs by means of organophilic clays is a function of several parameters including the type and amount of the clay, the synthetic based fluid, the composition of the internal dispersed phase, mixing time, and the type of emulsifier.

The impact of the synthetic-based fluid, i.e. an ester, olefin, or a paraffin, organophilic clays, water, calcium chloride, emulsifiers, and the mixing time on the rheological behavior of the produced mud was thoroughly investigated. Micrographs from scanning electron microscope (SEM) revealed that the presence of water has a vital role on the dispersion of clay in the fluid while presence of calcium chloride lowers both the stability of the fluid and the dispersion of the clay. Samples containing calcium chloride exhibited instability and phase separation within a 24-hours period. SEM micrographs and rheological measurements also revealed that the degree of clay dispersion depends on the polarity of the base fluid and the interaction of the polar groups in the fluid molecules with those of clays. The observations on the prepared samples at ambient temperature demonstrated that the minimum amount of clay content for a homogeneous and stable fluid is about 6 lb/bbl. The latter observation also confirmed the role of the organophilic clays on the stability of the invert emulsions.

Investigations on the effect of shear time on the viscosity of the fluids at ambient temperature resulted in a more appropriate thixotropic properties for esters in comparison with olefins and paraffins, e.g. ester based fluids reached the maximum viscosity after 20 minutes of mixing while that was about 60 minutes for the paraffin and olefin based fluids. The latter observation clearly demonstrates the superior dispersion behavior of the clays in esters. The occurrence of maximum viscosities shifted toward lower mixing times at elevated temperatures. This observation shows the favorable influence of the temperature on the thixotropic behavior of the SBFs.
The Experimental Study of Formation Damage During UBD Operation in the Fractured Carbonate Formations
Authors: Salimi S. , Ghalambor A. , Tronvoll J. , Alikarami R.
Published: February 2008

This paper describes an experimental investigation of formation damage during underbalanced drilling (UBD) conditions in a fractured carbonate core sample. A major portion of this study has concentrated on problems, which are often associated with UBD and the development of a detailed protocol for proper design and execution of an UBD program. Formation damage effects have been studied, which may occur even if the underbalanced pressure condition is maintained 100% of the time during drilling operation. One major concern to formation damage during UBD operations is the loss of the underbalanced pressure condition. Hence, it becomes vital to evaluate the sensitivity of the formation to the effect of an overbalanced pulse situation. The paper investigates the effect of short pulse overbalance pressure during underbalanced conditions in a fractured chalk core sample. Special core tests using a specially designed core holder are conducted on the subject reservoir core. Both overbalance and underbalanced tests are conducted with four UBD drilling fluids. Core testing is including the initial permeability measurement and return permeability after two different conditions of pressure (underbalanced and overbalance). Then the procedure is followed by applying a differential pressure on the core samples to mimic the drawdown effect to present capacity of the return permeability. In both UBD and short pulse OBP four mud formulation are used which are, lab oil, Brine (3% KCL), Based mud (Bentointe with XC polymer) and fresh water. The return permeability measurements show that a lab oil system performed fairly well during UBD and short OB conditions. The results indicate that short overbalance pressure provides significant reduction in permeability of the fractured carbonate formations. In most tests, even application of a high drawdown pressure during production cannot restore the initial permeability more than 40%.
Equalization of the Water Injection Profile of a Subsea Horizontal Well: A Case History
Authors: Amaral Anderson da S. , Augustine Jody , Henriksen Knut , Rodrigues Valdo Ferreira , Steagal Daniel Escobar , Paixão Luiz Carlos Alves da , Barbosa Pereira
Published: February 2008

This paper focuses on the first global installation of a water injector well with a lower completion system that incorporates both premium sand control screens and water injection profile equalization. The equalization of the water injection profile of horizontal wells has been a key issue in many development projects worldwide and has the potential to increase the reservoirs ultimate recovery by increasing the water sweep efficiency.

Inflow Control Devices integrated with premium sand control screens have a long history of application in production wells. In these cases the main objective is to create a uniform inflow profile along the horizontal section, delaying unwanted water and gas production and increasing oil recovery. The method through which Inflow Control Devices equalize the inflow of oil can also be used to equalize the outflow of water. Historically, sand control completions for water injection wells include stand-alone conventional screens and open-hole gravel packs. Stand-alone conventional screen completions do not provide equalization of the water injection profile. Open-hole gravel packs provide for an effective acid treatment of the water injector well but present operational risks, high costs, as well as expensive rig time.

The installation was carried out in a subsea horizontal sea water injector well in the Campos Basin, offshore Brazil. The paper presents the overall completion plan, the lower completion installation, the acid treatment through the Inflow Control Devices, and the initial water injection results based on production logs and water injectivity tests. The main concerns during the planning phase are discussed, highlighting the procedures adopted to overcome them.

The good initial results have created the expectation of many applications of this system in Campos Basin. It is believed that sharing this information will benefit many operators with horizontal water injectors in their field development plans.
New Agent for Formation-Damage Mitigation in Heavy-Oil Reservoir: Mechanism and Application
Authors: Wang Y. , Kantzas A. , Li B. , Li Z. , Wang Q. , Zhao M.
Published: February 2008

Migration of formation fines has been shown to cause production decline in many wells, especially for sand production wells in heavy oil reservoir. Filter cakes in wire wrapped liner, which were formed by the attachment of viscous crude oil blended with formation fines, may block the flow paths of viscous oil. The solution to this problem is appropriate treatment to mitigate this type of formation damage.

In this paper the performance at laboratory-scale of a new type of agent for formation damage mitigation is presented and some guidelines for its application including the injected pore volume and injection concentration are provided.

The mechanism for damage mitigation with this type of agent in heavy oil reservoir was introduced in detail, it mainly include that this type of agent can reduce interfacial tension between crude oil and water and change the wettability of rock surface, which may lead to the breakaway of resins and asphaltenes attached to the rock surface.

By simulation experiments and core flood tests the effectiveness of this type of agent to mitigate the damage in heavy oil reservoir was identified. Simulation experiment results show that, damage mitigation in cores with the permeability higher than 1μm2, is more effective than those with the permeability lower than 1μm2, and core flood experiment results also indicate that this type of agent with the concentration of higher than 5% can remarkably increase recovery factor for cores with the permeability higher than 1μm2. Finally some results on the behaviour of its application in heavy oil reservoir are presented.
An Experimental Investigation of Drilling-Fluid Filter-Cake Removal by Acid Jetting
Authors: Mikhailov M. , Zhu D. , Hill A. D.
Published: February 2008

Acid jetting from ports near the end of a tubing string is a common method being applied to remove drilling or completion fluid filter cakes and to stimulate near-wellbore permeability. To be effective, the acid jet must remove enough of the filter cake to eliminate any significant filter cake Δp, and should stimulate some distance into the formation if internal damage has occurred. In this study, we experimentally evaluated the efficiency of acid jetting at conditions similar to those being applied in the field. The results obtained with acid jetting were compared with those obtained jetting with water alone to determine the relative importance of the mechanical removal of the filter cake by the liquid jet and the dissolution of filter cake and formation solids by the acid.

We first created a drilling fluid filter cake and internal damage by circulating a typical drill-in fluid containing sized CaCO3 particles past the face of a 4-inch diameter by 18-inch long core for up to 18 hours. A pressure differential of 500 psi was held across the core to drive filtrate and possibly solids invasion into the rock. Acid (15% HCl) was then jetted from a small port on to the center of the core face at velocities typical of field applications. The velocity and duration of jetting was varied systematically in the experiments. In each experiment, we measured the evolving permeability of the filter cake/core system by measuring the pressure drop across the system.

In this paper, we show how the key parameters of jet velocity and duration of jetting affect jetting efficiency. Comparison of the acid jetting results with those obtained jetting with water alone show how much of the cleanup is accomplished by the mechanical action of the liquid jet compared with the chemical dissolution of the solids by the acid. In many cases, the jetting action provides the primary restoration of productivity with less effect caused by acid dissolution.
Well Stimulation and Gravity Segregation in Gas Improved Oil Recovery
Authors: Jamshidnezhad M. , Chen C. , Kool P. , Rossen W. R.
Published: February 2008

Models for gravity segregation in gas improved oil recovery (IOR) indicate that the distance injected gas and water travel together before complete segregation scales with the injection rate Q. Therefore, in cases where injection pressure is limiting, reducing skin resulting from damage at the wellbore face directly increases volumetric sweep of gas in IOR. Even in the absence of damage at the wellbore face, most of the injection pressure is dissipated near the well, but most of the segregation occurs much further from the well. Therefore, if injection pressure is limited, increasing mobility near the injection well has a large impact on Q, with a direct benefit in delaying gravity segregation. There is also a relatively small increase in gravity segregation in the near-well region. An analytical model for gravity segregation in homogeneous reservoirs can be extended to a case where permeability is stimulated within a cylindrical region inside a larger cylindrical reservoir. The effect of this stimulation in increasing Q at fixed injection pressure can be estimated as well. One can increase the volume swept by gas before segregation by as much as 170%, though a large volume must be stimulated to reach this optimum.

The model represents schematically a number of ways proposed in gas IOR for delaying segregation beyond the possibilities with uniform, steady co-injection of Newtonian fluids: alternate injection of gas and liquid (WAG, or SAG with foam); injection of gas above water; and injection of shear-thinning foam. In all these cases the process gives higher mobility near the well, allowing an increase in injection rate, and thereby increases the distance to the point of segregation.

The model can be extended directly to the case of shear-thinning (power-law) foam. One obtains a differential equation for the segregation process, in place of the algebraic equation that results for Newtonian fluids. In the limit of extremely shearthinning behavior, it is possible to double the distance to the point of segregation with no increase in injection pressure. Simulations fit the theoretical prediction well.
Method to Pump Bridge/Frac Plugs at Reduced Fluid Rate
Authors: Smith Don , Starr Phillip
Published: February 2008

This case-history paper presents hardware and a method to enable pumping frac plugs and bridge plugs into horizontal wells, using substantially less fluid than used by conventional pumpdown means. Cases presented are from operations in the Barnett Shale formation of north Texas.

The system presented was developed in response to (1) the need to conserve well fluids used and (2) high pumping rates needed to pump frac plugs and bridge plugs to setting depths in horizontal holes. Fluids bypassing the plug without exerting enough push on the plug necessitated application of high pump rates and total fluid volumes.

Advantages of (1) using new sealing methods to reduce fluid requirements, and (2) following a set of procedures to pump plugs to the setting depth in horizontal wells are numerous: Total volume of water needed is greatly reduced.Lower pumping rates allow for the use of wireline when tight formations are encountered.Precludes the requirement to bring in more expensive and time-consuming methods of placing the plugs to depth, such as hydraulic tractors or coiled tubing units.Saves time and fluid costs.Reduces chances of damaging reservoirs with excess pumpdown fluid.Fluid flow around the sealing device provides a jetting action ahead of the tool to disperse sand and debris ahead of the plug in horizontal casing, based on field experience.As compared to that of hydraulic tractors, the system enables high travel rate for wireline, up to 150 ft/min.

The paper presents procedures for running plug-sealing devices that reduce the bypass of fluid between the plug and casing wall. The system has been in use for about 1 year; field experience, lessons learned, and application tips are also presented.
Radial Profiling for Completion Effectiveness With New Sonic Measurement in the Gulf of Thailand
Authors: Jiang Long , Schilling Keith , Logan Jim
Published: February 2008

Acoustic measurements have long been used to evaluate rock properties in the near-wellbore region and these methods are well documented. Comprehensive characterization of the wellbore rock relies on the knowledge of compressional and shear slowness in the axial, azimuthal, and radial directions. A recent evaluation in the Gulf of Thailand demonstrates that an understanding of the radial variations may prove extremely valuable in our understanding of completion effectiveness and may provide further insight into changes required in drilling practices or drilling fluid management. Acoustic variations in the near-wellbore region can arise as a result of nonuniform stress distributions, mechanical or chemical near-wellbore alteration from the drilling process, and formation intrinsic anisotropy related to in-situ properties of the formation. This document will explore results from acoustic measurements and interpretation of the near-wellbore resulting in operative information. Combined with measurements of formation properties this information can provide an accurate assessment of the drilling environment and the reservoir. This knowledge can lead to reduced overall drilling costs, improved recovery, and productivity.
Sanding Study for Deepwater Indonesia Development Wells: A Case History of Prediction and Production
Authors: Palmer Ian D. , Higgs Nigel G. , Mathers Robert M. , Herman Scott R.
Published: February 2008

A detailed sand prediction has been made for three wells at Chevron's West Seno field based on logs/lab data and the results have been calibrated with production data. Both maximum allowable drawdown and depletion increase with depth. Additionally, oriented perforations offer an improvement to perforation stability against sanding: the maximum allowable drawdowns and depletions are increased for all sands. Finally, an analysis is presented on the economics and trade-offs of vertically-oriented perforating (with possibly managed sand production) versus frac-packing. Sand onset prediction agrees fairly well with the observed drawdown/depletion for horizontal perforations. This benchmarking appears to support the validity of the shear-failure model. This is important because the model, while fairly simple, has many different inputs, including depth profiles for unconfined compressive strength (UCS) and in-situ stresses, which involve sophisticated prediction techniques themselves. Continuous sand rates (for oil wells) have also been predicted by extending the shear-failure sanding model. As depletion increases over time, added perforation intervals begin to fail/collapse, increasing the sand rate. There are periods of agreement and underestimation (by a factor of ~4) between observation and prediction. This is important because it is the first time this model has been benchmarked against observation at early times in a well's life. It appears the model can provide a first estimate of sanding levels in oil wells, which are useful to assist the design of well facilities for dealing with sand. Finally, a sand prediction was used to evaluate oriented perforating in lieu of frac-packed completions. The evaluation defined production scenarios, by building nodal and production forecast models, and ran incremental economics. It indicated that oriented perforating can provide favorable economics over frac-packs if critical rock properties and production plans are defined and understood.
Experience With Chemical Sand Consolidation as a Remedial Sand-Control Option on the Heidrun Field
Authors: Haavind F. , Bekkelund S. S. , Moen A. , Kotlar H. K. , Andrews J. S. , Håland T.
Published: February 2008

The Heidrun field located in the Norwegian Sea is an oil and gas producing field which has been developed with a tension leg platform (TLP) installed over a template with 56 slots. Two subsea production templates and three subsea water injection templates are also tied back to the TLP. All wells require sand control measures in the reservoir section to prevent sand production. The sand control philosophy has gradually evolved from cased hole gravel packs, through stand alone screens to todays preferred option of openhole gravel packing. Sand control in the field is challenging with high fines content in the reservoir and a potential for plugging from scaling from secondary recovery with seawater. Sand control integrity has failed in some wells and offtake rates in these wells are limited to Maximum Sand Free Rates (MSFR). In some cases intervention is required for remedial sand control or new sidetracks are planned. However, for a number of suitable wells, chemical treatments that consolidate the near wellbore area can be a viable alternative to improve well offtake rates.

The chemical treatment is mixed in diesel and bullheaded in the well. The active chemical will react with the connate water in the near wellbore area and form a polymerized network which binds the sand grains together. In that way, the residual strength of the formation is increased and can withstand larger hydrodynamic forces before the grains are transported into the wellbore.

To date three Heidrun wells have been treated with the sand consolidating chemical that has been developed in-house. Two of these are platform wells and the third is subsea. One of the platform wells has been retreated twice following a successful first treatment. This work describes the five different treatments; the planning, the execution and the post-job analysis. One of the treatments was not successful, another one was very successful. The reasons behind these results will be discussed.
Successful Stimulation of Thick, Naturally-Fractured Carbonates Pay Zones in Kazakhstan
Authors: Arangath R. , Hopkins K. W. , Lungershausen D. , Bolyspayev N. T.
Published: February 2008

Stimulation of carbonate reservoirs is often considered a routine operation. When the reservoirs are thick (more than 200 m) the stimulation process is much more complex because factors such as reservoir heterogeneity, damage to each zone, matrix mineralogical composition, and pressure regimes of each zone need to be taken into consideration. The presence of natural fractures makes the entire treatment more complex.

Acid placement and diversion need to be carefully designed and optimized to effectively stimulate the wells by reducing the skin factor to the lowest possible value in each zone. At the same time, the selected optimum acid system, placement, and diversion techniques need to be applicable in the field in a simple manner without impacting the overall treatment logistics.

The use of a hydrochloric acid system containing a viscoelastic surfactant system that allows, upon acid spending, the development of viscosity in situ, has shown that significant skin reductions can be obtained provided the proper placement techniques are used. However, in certain cases where natural fractures are dominant, diversion effects can be noticed but are not optimal. An enhanced system that contains temperature-degradable fibers has been used in Kazakhstan. Such systems are shown to successfully divert and stimulate effectively even when natural fractures are dominant.

This paper presents experiences with different types of acid placements and diversion techniques in the thick carbonate reservoirs of western Kazakhstan. Pretreatment and post-treatment production data have been analyzed to evaluate the effectiveness of the treatments in terms of skin reduction or productivity index increase.
Formation Damage Induced by Various Water-Based Fluids Used to Drill HP/HT Wells
Authors: Al-Yami A. S. , Nasr-El-Din H. A. , Bataweel M. A. , Al-Majed A. A. , Menouar H.
Published: February 2008

Drilling Unayzah-B reservoir (shale and sandstone) in Saudi Arabia requires high mud density (± 95 pcf) to mechanically stabilize the shale and balance the reservoir pressure. Two fluids are used to drill this reservoir: KCl/ BaSO4/ CaCO3 whereas the second is potassium formate/CaCO3. Barite is added with CaCO3 to reduce the amount of solids needed to formulate the drill-in fluid. However, BaSO4 is insoluble in acids and requires chelating agents to remove it from the formation. Formate drill-in fluids with low solid content can then be used, but they are expensive and corrosive at pH values less than 7-8. To overcome some of the problems associated with these two systems Saudi Aramco developed water-based drill-in fluids using Mn3O4. No similar formulations were developed before to the best of the authors' knowledge.

The objective of this study is to determine formation damage induced by KCl/Mn3O4 mud at 95 pcf. A mini-flow loop was used to assess formation damage induced by the three the drill-in fluids. The experiments were conducted using reservoir cores at bottom hole conditions. Another set of experiments were conducted using a dynamic HPHT cell to determine the thickness and composition of the filter cake filter cake, spurt loss and chemical analysis of filtrate. Compatibility tests between mud filtrate and produced water were performed at 300 °F and 500 psi using see through cells.

The KCl/Mn3O4 showed the least formation damage compared to the other two fluids. The return permeability was significantly higher than those obtained with potassium formate/CaCO3 or BaSO4/CaCO3 mud systems. Potassium formate filtrate was not compatible with Unayzah-b formation brine, which resulted in its low return permeability (42%) in spite of its low solids content. Unlike formate based fluids, mud filtrate of KCl/Mn3O4 was compatible with the formation brine. BaSO4/CaCO3 drill-in fluid resulted in 40% because the barite solids were trapped inside the core. KCl/Mn3O4 drill-in fluid resulted in 70% return permeability. The main reason for this high result is the spherical shape and small size of Mn3O4 particles, which allowed them to be removed by flow of hydrocarbons.
Characteristics and Removal of Filter Cake Formed by Formate-Based Drilling Mud
Authors: Al Otaibi M. B. , Nasr-El-Din H. A. , Hill A. D.
Published: February 2008

Formate-based mud has been used to drill deep gas wells in Saudi Arabia since 2004. This mud typically contains XC-polymer, starch, polyanionic cellulose, and a relatively small amount of calcium carbonate particles. This mud (typically 90 pcf, pH of 10) is used to drill a deep sandstone reservoir (310°F). Various cleaning fluids were proposed to remove drilling mud filter cake; including: solids-free formate brine, formate brine doped with organic acids (acetic, formic, citric, and lactic acids), and enzymes. The main objective of this paper is to assess the effectiveness of these cleaning fluids in removing formate drilling mud filter cake.

A dynamic HPHT cell was first used to determine characteristics of the formate mud filter cake. Drilling mud and completion fluids were obtained from the field. The experiments were conducted using ceramic disks at bottom hole conditions. Compatibility tests between formate brine and cleaning fluids were performed at 300°F and 500 psi using HPHT visual cells (see-through cells).

Circulation of solids-free formate brine did not remove the external filter cake. Citric acid at 10 wt%, formic acid, and lactic acid were found to be incompatible with formate brine at room temperature. However, these acids were compatible with formate brine at temperatures greater than 122°F. Mixing of these acids with the formate in the field may cause operational problems. Only acetic acid and enzymes were compatible with formate brine. A formula was developed that is compatible at room and reservoir temperature. This formula was effective in removing filter cake. A corrosion inhibitor was added to protect downhole tubulars. This paper will discuss the development of this formula and all tests that led to its development.
A Faster Cleanup, Produced-Water-Compatible Fracturing Fluid: Fluid Designs and Field Case Studies
Authors: Bulat Daren , Chen Yiyan , Graham Matthew K. , Marcinew Richard , Adeogun Goke , Sheng Jack , Abad Carlos
Published: February 2008

Natural gas reservoir development continues at a record pace in North America. Additionally, reservoir pressure depletion and declining quality of reserves have resulted in escalating drilling, completion, and workover costs per unit of gas produced. This in turn forced industry to focus on increasing efficiency by refining completion processes and field operations to make wells commercially viable. Strategies such as multiple-zone commingled completions, the selection of fluids and additives to maximize hydraulic fracture effective length and conductivity, and fluid recycling/handling are but a few strategies employed. Additionally, operating companies have been seeking other cost-control measures, including reducing the number of additives in fracture fluids and minimizing disposal costs of produced waters by recycling and by using them as the base for completion and fracturing fluids. Because of the uncertainty of the produced water impurity, composition, and concentration, it is extremely challenging to make a fracturing fluid compatible with produced water. Together with the need to gel produced water, the demand for more conductive fractures, along with the capacity to create sufficient fracture geometry, has led to the development of a unique surfactant-based system relatively insensitive to most produced waters, and even to some high-density brines. Fluid chemistry modifications employed to enhance performance allowed for reductions in mix-water and fluid-handling costs, shortened flowback/cleanup time, and provided equal or improved post-fracture production response. This paper focuses on a description of the fluid chemistry and performance along with numerous fracture treatment applications with a variety of mix-waters.