bluuebunny/crossref_metadata_2025_split huggingface dataset:
Gas Condensate Productivity Improvement by Chemical Wettability Alteration
Authors: Delavarmoghaddam A. , Mirhaj S. A. , Zitha P. L. J. 
Published: May 2009

Abstract
Gas condensate reservoirs with a bottom-hole flowing pressure (BHFP) below the dew point pressure (DPP) suffer from productivity loss of both gas and condensate due to the accumulation of condensate in the near the wellbore. Methods used to restore the productivity, including solvent treatment and hydraulic fracturing, suffer from various limitations and may be effective only temporarily. A recently proposed method to restore well productivity in retrograde condensate wells is chemical wettability alteration in the near-wellbore zone using adsorbed polymers or surfactants. In this paper the gas condensate studies are critically reviewed and the potential of wettability alteration evaluated using reservoir simulations. Radial flow in a prototypical gas condensate reservoir is simulated using the compositional simulator GEM of the CMG suite. The simulations are done in two parts: first several years of production without chemical treatment are considered. Then a new relative permeability set is defined for the treated area around the wellbore. The modified relative permeabilities are developed based on existing experimental studies, by inserting new residual saturations in Honarpour's relative permeability model. A detailed discussion of the assumptions and limitations of this model is offered. The simulation is also run for three different permeabilities. High permeable rocks show smaller amount of condensate trapping in the models run. The flow rate is higher in treated reservoirs due to smaller residual liquid saturation.
Formation Damage and Well Productivity Simulation
Authors: Lohne Arild , Han Liqun , van der Zwaag Claas , van Velzen Hans , Mathisen Anne-Mette , Twynam Allan , Hendriks Wim , Bulgachev Roman , Hatzignatiou Dimitrios G. 
Published: May 2009

Abstract
In this paper we describe a simulation model for computing the formation damage imposed on the formation during overbalanced drilling. The main parts modelled are filter cake build-up under both static and dynamic conditions, fluid loss to the formation, transport of solids and polymers inside the formation including effects of pore lining retention and pore throat plugging, and salinity effects on fines stability and clay swelling. The developed model can handle multi-component water-based mud systems at both the core scale (linear model) and the field scale (2D radial model). Among the computed results are fluid-loss versus time, internal damage distribution and productivity calculations for both the entire well and individual sections.
The simulation model works in part independent on fluid loss experiments, e.g., we do not use fluid leakoff coefficients, but instead we compute the filter cake buildup and its flow resistance from properties ascribed to the individual components in the mud. Some of these properties can be measured directly, such as particle size distribution of solids, effect of polymers on fluid viscosity and formation permeability and porosity. Other properties, which must be determined by tuning the results of the numerical model against fluid loss experiments, are still assumed to be rather case independent, and once determined they can be used in simulations at altered conditions as well as with different mud formulations. A detailed description of the filter cake model is given in the paper.
We present simulations of several static and dynamic fluid loss experiments. The particle transport model is used to simulate a dilute particle injection experiment taken from the literature. Finally, we demonstrate the model's applicability at the field scale and present computational results from an actual well drilled in the North Sea. These results are analysed and it is concluded that the potential impact of the mechanistic modelling approach used is (a) increased understanding of damage mechanisms, (b) improved design of experiments used in the selection process and (c) better predictions at the well scale. This allows for a more efficient and more realistic pre-screening of drilling fluids than traditional core plug testing.
Sand Control Screen Erosion – When Are You at Risk?
Authors: Gillespie George , Jones Colin 
Published: May 2009

Abstract
For Stand Alone Screen (SAS) completions in open hole oil/gas wells, the sand control screen must retain the formation sand effectively, and provide a conduit for fluids to flow into a producing well. The screen's performance and service life depends on the well's operating conditions. A failure may occur while completing the well, or at some time during the well's operating life. The root cause of the screen failure is often difficult to determine with absolute accuracy. Often, it is determined that screen failure occurs due to a combination of plugging and erosion resulting in the loss of sand control.
A comprehensive test program was undertaken over a two year period to evaluate erosion of different screen types for open hole completions. Completions were simulated for wire wrap and metal mesh sand screens commonly used in open hole completions.
Configurations of each screen type were installed in a test fixture, and several tests were conducted at different velocities and sand concentrations. The sand was sized to pass through the screen with minimal plugging, which would simulate fines production over time in a producing well. The specific wear rates and per cent of rate loss were determined for each test. Micro photos were used in the analysis of the wear patterns, along with pre and post test measurements of the wire wrap slots or metal mesh pore sizes.
This paper will describe the test methods used, the test results and lessons learned, and will describe a model that can be used to predict a screen's service life based on a given set of well conditions in a SAS open hole completion.
Combining the Prediction of Penetration Depth of Downhole Perforators with the Depth of Invasion
Authors: Gladkikh Mikhail , LeCompte Brian , Harvey William , Makarov Alexander , Antonov Yuriy , Halleck Phillip M. 
Published: May 2009

Abstract
Formation fluids are displaced by drilling mud filtrate as a result of pressure overbalance during drilling. This process changes the petrophysical properties of the near-wellbore zone and creates an invasion zone that has a complex radial profile characterized by the partially decreased porosity, permeability, and altered saturations. Further, at the completion stage the well is cased, cemented, and then perforated to re-establish connection between wellbore and reservoir. During perforation, a shaped charge produces a jet of dense material traveling at very high velocity which penetrates casing, cement, and formation. The resulting tunnel is a rugose tapered cylinder roughly characterized by its diameter and total depth of penetration.
One of the main goals of perforated completion is to ensure fluid flow from the productive reservoir interval to the wellbore. Equally important is the ability of the jet to penetrate beyond the zone of formation damage caused by drilling, connecting the wellbore to the virgin reservoir and alleviating the effect of formation damage on production. The ability to predict the invasion depth and the depth of penetration of downhole perforators is therefore critical for pre-job completion modeling.
This work presents the results of numerical modeling predictions of both drilling mud filtrate invasion during drilling and jet penetration in rock during perforation. The invasion model is further applied to the well data interpretation, and a good agreement with log resistivity profile is shown. In addition, we review and discuss various empirical methods currently used in the industry to predict penetration depth. Despite a variety of available methods and published experimental data, penetration depth results are often inconsistent with each other and are of questionable use in predicting actual downhole penetration.
We highlight the importance of combining accurate invasion and penetration models for the successful pre-job completion planning. The results should be used further with the well-inflow model to maximize well productivity and minimize the effect of formation damage.
Computing True Formation Pressure Using Drilling and Logging Data
Authors: Antonov Yuriy , Wu Jianghui , Kashevarov Aleksander , Makarov Alexander , Gladkikh Mikhail 
Published: May 2009

Abstract
In order to ensure well stability, distinguish high- and low- pressure zones and estimate the level of pressure depletion, information about formation pressure is necessary. Due to formation damage during drilling and mud filtrate invasion, true formation pressure can not be measured directly when formation permeability is relatively small. Therefore, an accurate model of invasion profile is required to calculate true formation pressure from formation testing data. This is possible to achieve by combining drilling with LWD and/or wireline logging data.
This paper describes a method of computing depth of invasion by inversion of resistivity logging data. We use resistivity image data to calculate flushed zone resistivity and induction logging data to compute true formation resistivity. This, in turn, provides an invasion zone profile and significantly reduces the ambiguity of possible solutions. Drilling regime, rate of penetration, wellhead pressure, and mud properties are used to calculate wellbore pressure. The changes in formation pressure during drilling are computed by the hydrodynamic model of invasion.
We present the result of formation testing data processing for water-saturated reservoir. The true formation pressure is estimated using the results of inversion, namely, estimate of mud filtrate volume penetrated into formation.
Carefully Designed Water-Based Drill-In Fluid and Filter Cake Removal System Improve Reservoir Producibility and Reduce Well Completion Costs
Authors: Al-Mehailani M. , Al-Anzi N. Abdullah , Gohain A. , Hussain I. , Haider B. , Davidson E. , MacMillan B. 
Published: May 2009

Abstract
Kuwait Oil Company introduced new fluid practices to improve producibility in the Minagish oolitic limestone reservoir in Umm Gudair field. The approach was designed to minimise formation damage in the reservoir section and apply a more effective filter cake removal technique during the well completion.
Experience on offset wells and results of return permeability studies showed that specially designed water-based drill-in fluids with optimally sized acid-soluble bridging particles were the preferred fluids for open hole completions on the Minagish reservoir. For removal of the cake and low permeability crush zone created by the drilling process a formic acid precursor (FAP) was used. The precursor is added to the completion fluid and reacts slowly with brine to release formic acid in the reservoir section. Conventional acidisation with HCl can cause wormholes, localised leak-off and failure to treat the entire interval effectively; FAP is in a neutral condition when placed. Localised reaction and loss zones are avoided and the released acid can act uniformly on the entire interval.
Four wells in this area were sidetracked due to depletion in pressure and increasing water cut. All utilized the same drill-in fluid. Subsequently wells UG 116ST and UG126ST were stimulated with HCl, whereas UG 38STRE and UG 110ST were treated with the FAP.. The two wells treated with the FAP had producibilities about twice those treated with HCl.
The combination of well designed drill-in fluid and FAP has shown great promise of facilitating the drilling process and increasing the producibility of the well with significant economic benefit. This paper addresses practical applications of the drill-in fluid and the breaker and reports on several additional benefits that were obtained.
Predicting Well Inflow Using Computational Fluid Dynamics—Closer to the Truth?
Authors: Byrne Michael , Jimenez Maria Alejandra , Chavez Juan Carlos 
Published: May 2009

Abstract
One of the great challenges facing our industry is accurate prediction of well inflow. Conventional methods have been too cumbersome and imprecise and have suffered from a lack of accuracy and clarity. Informed use of computational fluid dynamics, fine scale modelling and improved computing power enable far more accurate prediction of the impact of formation damage and thus of well performance.
The accurate prediction of well performance helps with appraisal of development prospects, well planning and reliable prediction of true well and field value. If we know what the outcome of our actions and of our well designs will be, then we can make sensible and informed choices on damage impact and mitigation.
Results from laboratory simulations of drilling and completion operations were generated from "standard" return permeability testing. The detailed data obtained, and its millimetre scale resolution was incorporated in to a well specific model. The damaged and undamaged states were examined using flow rate predictive computational fluid dynamics. The impact on flow in a single and dual permeability reservoir interval were calculated. In a specific example presented, the case for underbalance drilling was clearly made as the impact of overbalance drilling was predicted to have a severe impact on well productivity.
The results of accurate and detailed laboratory simulation of formation damage have been translated using innovative software applications to give a prediction of well performance. This is the first time that computational fluid dynamics has been employed to predict well performance based on high quality laboratory testing. In future the laboratory tests will be designed to yield data most useful for the model and the model and grid scale will continue to be adjusted based on the specific challenge and objective. The detailed workflow used to achieve more accurate well performance prediction will be outlined in the paper.
Formation Damage Zone Radius and its Applications to Well Stimulation
Authors: Nunes M. , Bedrikovetsky P. , Newbery B. , Paiva R. , Furtado C. , de Souza A. L. 
Published: May 2009

Abstract
Flow of particulate suspension in porous media with particle retention and consequent permeability reduction is discussed. Using analytical model for suspension injection via single well, the permeability damage zone size was defined and expressed by transcendental equation. Analysis of field data shows that usually the size of damaged zone does not extend more than one meter beyond the injector. The definition of damage zone size is used for design of well stimulation via deposition removal.
A Successful Expandable Sand Screen Case History in a Deep, Corrosive Gas Well Application
Authors: Ginest Noel , Al-Sagr Abdulaziz , Al-Malki Bandar , Al-Khawajah Muhammad , Jones Colin , Morgan Quentin , Parry Keith 
Published: May 2009

Abstract
K Field is a gas field located in Saudi Arabia, with production from the Unayzah A reservoir, an unconsolidated sandstone reservoir notable for its comparative depth. The high corresponding bottomhole temperature combined with corrosive gas properties manifests in aggressive in-situ corrosion conditions. Sand control is needed in this reservoir due to the weak rocks and high tectonic stresses. Frac-pack completions have been used successfully for a number of years and typically manifest in a low positive skin. They tend to suffer from condensate banking and flow related skin.
A number of years ago it was decided to use the then novel expandable sand screen (ESS) technology in a long horizontal well to maximise reservoir drainage. This presented many challenges in terms of the metallurgy, the interaction with high stresses and the deployment in a deep hot well. In April 2004 Well K-3 was drilled as a horizontal open hole well and completed with ESS, setting three world records at that time for the hottest and deepest ESS installation and first ever Incoloy ESS system.
The well was shut-in almost immediately after clean-up operations began due to a mechanical failure in the upper completion, and remained shut-in for nearly 3 years. The well was successfully restarted after an upper completion workover.
This paper describes assessment of well performance from a multi-rate production test conducted following successful workover of Well K-3, and benchmarks key performance indices with those derived from analysis of neighbouring wells equipped with alternative sand control techniques.
How Does Treatment Satisfaction Work?
Authors: Peyrot Mark , Rubin Richard R. 
Published: May 2009

OBJECTIVE
This study tested a model hypothesizing that treatment affects objective clinical outcomes, which in turn affect perceived consequences, which in turn affect satisfaction and preference judgments.

RESEARCH DESIGN AND METHODS
The model was tested in a double-blind, randomized clinical trial in which 266 patients with type 1 diabetes added active or placebo pramlintide to their insulin regimens. Objective clinical outcomes included changes in glucose and weight control, insulin requirements, incidence of hypoglycemia, and study drug tolerance. At the end of the trial, patients completed the validated PRAM-TSQ questionnaire measuring treatment satisfaction and preference and perceived medication benefits and side effects.

RESULTS
Statistical modeling demonstrated that active pramlintide was significantly associated with greater treatment satisfaction, preference, and perceived benefits (all except hypoglycemia prevention), as well as objective clinical outcomes (weight loss, lower postprandial glucose [PPG], lower medication tolerance, more hypoglycemia). Perceptions of treatment consequences were sensitive and specific to their cognate objective clinical outcomes (no halo effects). Clinical outcomes (especially PPG) accounted for almost half of the effect of the study medication on treatment satisfaction and preference. Treatment satisfaction and preference were strongly related to the perceived benefits/side effects of the study medication, and these perceptions (especially glucose control) mediated most of the association of clinical outcomes with satisfaction and preference.

CONCLUSIONS
This model received substantial empirical support. Improvements in objective clinical outcomes accounted for a large part of the association of pramlintide treatment with higher treatment satisfaction and preference. Perceived treatment consequences mediated the effect of objective clinical benefits on satisfaction with and preference for the study medication.
Treatment of Symptomatic Polyneuropathy With Actovegin in Type 2 Diabetic Patients
Authors: Ziegler Dan , Movsesyan Lusine , Mankovsky Boris , Gurieva Irina , Abylaiuly Zhangentkhan , Strokov Igor 
Published: May 2009

OBJECTIVE
To evaluate the efficacy and safety of actovegin in patients with diabetic polyneuropathy.

RESEARCH DESIGN AND METHODS
In this multicenter, randomized, double-blind trial, 567 patients with type 2 diabetes received 20 intravenous infusions of actovegin (2,000 mg/day) (n = 281) or placebo (n = 286) once daily followed by three tablets of actovegin (1,800 mg/day) or placebo three times daily for 140 days. Total symptom score (TSS) of the lower limbs and vibration perception threshold (VPT) were used as coprimary outcome measures, computed as the area under the curve (AUC) from repeated scores and divided by duration of exposure. Secondary end points included individual TSS symptoms, neuropathy impairment score of the lower limbs (NIS-LL), and quality of life (short form [SF]-36).

RESULTS
TSS was significantly improved during actovegin treatment compared with placebo, as assessed by AUC (−0.56 points [95% CI −0.85 to −0.27]; P = 0.0003), and from baseline to 160 days (−0.86 points [−1.22 to −0.50]; P &lt; 0.0001). VPT (five sites per foot) decreased by 3% (95% CI 0–6; P = 0.084) with actovegin than placebo, as assessed by AUC, and by 5% (1–9; P = 0.017) after 160 days. NIS-LL sensory function, as assessed by AUC, was significantly improved with actovegin versus placebo (−0.25 [95% CI −0.46 to −0.04]; P = 0.021), as was the SF-36 mental health domain. There were no differences in the incidence of adverse events between the groups.

CONCLUSIONS
Sequential intravenous and oral actovegin treatment over 160 days improved neuropathic symptoms, VPT, sensory function, and quality of life in type 2 diabetic patients with symptomatic polyneuropathy.
Relationship of perfusion pressure and size to risk of hemorrhage from arteriovenous malformations
Authors: Spetzler Robert F. , Hargraves Ronald W. , McCormick Patrick W. , Zabramski Joseph M. , Flom Richard A. , Zimmerman Richard S. 
Published: May 2009

✓ The relationship between the size of an arteriovenous malformation (AVM) and its propensity to hemorrhage is unclear. Although nidus volume increases geometrically with respect to AVM diameter, hemorrhages are at least as common, in small AVM's compared to large AVM's. The authors prospectively evaluated 92 AVM's for nidus size, hematoma size, and arterial feeding pressure to determine if these variables influence the tendency to hemorrhage.
Small AVM's (diameter ≤ 3 cm) presented with hemorrhage significantly more often (p < 0.001) than large AVM's (diameter > 6 cm), the incidence being 82% versus 21%. Intraoperative arterial pressures were recorded from the main feeding vessel(s) in 24 of the 92 patients in this series: 10 presented with hemorrhage and 14 presented with other neurological symptoms. In the AVM's that had hemorrhaged, the mean difference between mean arterial blood pressure and the feeding artery pressure was 6.5 mm Hg (range 2 to 15 mm Hg). In the AVM's that did not rupture, this difference was 40 mm Hg (range 17 to 63 mm Hg). Smaller AVM's had significantly higher feeding artery pressures (p < 0.05) than did larger AVM's, and they were associated with large hemorrhages. It is suggested that differences in arterial feeding pressure may be responsible for the observed relationship between the size of AVM's and the frequency and severity of hemorrhage.