bluuebunny/crossref_metadata_2025_split huggingface dataset:
Evaluación de trastornos de la personalidad en pacientes heroinómanos mediante el International Personality Disorders Examination (IPDE)
Authors: San Narciso G. I. , Gutiérrez E. , Saiz P. A. , González Mª R. , Bascarán Mª T, , Bobes J. 
Published: April 2016

Objetivos.- Determinar 1. Prevalencia de trastornos de la personalidad (TP) en pacientes adictos a opiáceos 2. Factores involucrados en la retención terapeútica a medio plazo (6 meses) 3. Indices de validez del módulo de screening del IPDE 4. Estabilidad diagnóstica a medio plazo del IPDE.Pacientes.- 262 pacientes (135 procedentes de centro público y 127 de centro privado), que consecutivamente demandaron tratamiento entre septiembre de 1996 y mayo de 1998. Dichos pacientes fueron asignados a las siguientes modalidades terapeúticas: Programa de Mantenimiento con Metadona (PMM) en centro público (n= 53), Programa de Mantenimiento con Naltrexona (PMN) en centro público (n= 82) y PMN en centro privado (n=127). Evaluación.- Versión Europea del Addiction Severity Index (EuropASI) e International Personality Disorders Examination (IPDE).Resultados y conclusiones.- Estudio basal: mayor prevalencia de TP en los pacientes sometidos a PMM. Los a distribución de TP varía en función de la modalidad terapeútica, así en PMM los TP más prevalentes son el disocial, límite y paranoide, en PMN público el disocial, ansioso y límite y en PMN privado el límite, disocial e impulsivo. En líneas generales, los adictos a opiáceos que cumplen criterios IPDE de TP presentan una mayor gravedad de su adicción.Estudio de seguimiento: el perfil de los pacientes que abandonan precozmente el tratamiento en PMN privado se caracteriza por: mayor dosis inicial de heroína consumida, mayor gravedad de la adicción (áreas de alcohol, drogas y estado psiquiátrico del EuropASI) y mayor número de diagnósticos IPDE de TP.Estudio de validez del IPDE: El módulo de screening del IPDE ha demostrado elevada sensibilidad y moderada especificidad. El IPDE se ha mostrado como un instrumento dotado de una adecuada estabilidad diagnóstica a medio plazo (6 meses).
Halite Deposition – Prediction and Laboratory Evaluation
Authors: Goodwin Neil , Graham Gordon M. , Frigo Dario M. , Kremer Egbert 
Published: April 2016

Abstract
This paper describes a laboratory and modelling study into halite (sodium chloride, rock salt) deposition in mature gas production wells. Halite deposition can result in significant production and integrity issues, and mitigation measures are primarily based upon injection of low-salinity wash water, often coupled with careful control of production parameters (such as well drawdown), for which scale-prediction models are used.
Laboratory investigation of halite scaling and performance of halite inhibitors typically uses the mixing of incompatible brines or cooling a saturated solution, either in bottle tests or using a dynamic scale rig. While these methods allow precipitation kinetics and inhibitor performance to be examined, they are far from ideal as they require significant modification of the brine chemistry and deposition conditions.
In this paper, we describe a novel approach to laboratory investigation of halite deposition that much more closely mimics the evaporative scaling mechanism mostly widely experienced in the field, and can be performed using produced-water compositions and conditions that are much more representative of the field. It is based upon a dynamic, flowing system where field-representative formation water is co-injected with gas at an appropriate level of under-saturation in water content to that expected under production conditions.
Electrolyte prediction software was used to model the halite scaling tendency in the experiments, and very good correlation was found between the prediction of supersaturation and the onset of precipitation and deposition. This agreement implies that the scale-prediction model is accurate for halite scaling via this mechanism, and adds much confidence to the use of this tool for optimizing production parameters to minimize the effects of halite scaling in the field. The work also confirms earlier reports that the critical scaling tendency for halite – the value at which significant precipitation and deposition occurs in the field – is very close to unity for the conditions tested in this work.
The new laboratory method was also used to generate calcium carbonate scaling by the mechanism – primarily transfer of CO2 to the gas phase – that is by far the predominant one found in the field; this led to observation of a mixed halite/calcium carbonate deposit.
Iron Sulphide Scale Management in High H2S and CO2 Carbonate Reservoirs
Authors: Verri G. , Sorbie K. S. , Singleton M. A. , Hinrichsen C. , Wang Q. , Chang F. F. , Ramachandran S. 
Published: April 2016

Abstract
Combined sulphide/carbonate scale formation in wells producing from high CO2 and H2S reservoirs represents a serious threat to production efficiency and system integrity. Understanding both (i) the main source of iron forming the iron sulphide scale, and (ii) the phase partitioning and effect of the acid gases (CO2 and H2S), are important in devising and implementing the correct sulphide scale control program.
In this paper, a PVT software package was used to take production data and model water condensation/evaporation, calculate gas compositional changes and CO2/H2S partitioning between the liquid phases. This enabled reservoir fluid compositions to be predicted using an in-house scale prediction software, with particular focus on the stable concentration of iron in the aqueous phase. A sensitivity study was then performed to assess the parameters which impact on iron solubility within the reservoir. With the reservoir fluid compositions established, changes along the production stream (over a given range of temperatures and pressures) were determined and used to predict scale formation at those conditions. A modelling workflow was developed and tested against field data for the prediction of sulphide/carbonate scale deposition in gas wells producing from carbonate reservoirs. The workflow was then applied to a number of Middle East gas wells which produce 2-4% CO2 and 2-6% H2S. By understanding changes in flow rate, gas partitioning and fluid composition along the production stream it was possible to map the potential scale deposition through the system and to compare these results with scale deposits observed in the field. It was calculated that the pH in the wellbore is low and mainly determined by the partial pressure of carbon dioxide. The pH in the reservoir is higher due to the presence of calcium carbonate. Thus, it was possible to determine that dissolved iron is highly unlikely to be present in the formation fluids leading to the conclusion that the source of iron for iron sulphide deposition to occur must be the result of sour corrosion. In addition, the resulting likely profiles of iron sulphide deposition were predicted.
Development of a Scale Inhibitor for Zr-Crosslinked Seawater Systems: A Case History of Successful Testing to Failure and Field Applications
Authors: Wylde Jonathan J. , Mahmoudkhani Amir 
Published: April 2016

Abstract
The development of deepwater, high temperature fracturing fluids for continued operations in the most challenging offshore environments in the world led to the need for high performance scale inhibitor additives to be developed. Many conventional scale inhibitors were either not compatible with the fluid (typically due to chelation of the zirconium cross-linker) or were not thermally stable at 350°F or above.
The requirement was to have a scale inhibitor that could inhibit both carbonate and sulfate scales, even at the elevated pH found in the frac fluid system. The scale inhibitor also needed to be suitable for deployment into both sandstone and carbonate reservoirs and be able to protect the near wellbore from formation damage caused by the injected fluids. Furthermore, the scale inhibitor was required to provide ongoing protections to the formation after fracture fluid flowback by exhibiting favorable adsorption / desorption behavior. This unique combination of requirements meant a back to basics approach needed to be taken and structure performance relationships developed for the main types of classic scale inhibitor chemistry functional groups.
The test methods employed and chemistry of products tested are reported in this paper. Details of the hydraulic fracturing fluid compatibility testing highlight the significant effect the wrong choice of chemical can have on rheology over a range of temperatures. Performance testing shows the effect that even small concentrations of zirconium can have on scale formation and inhibition at elevated pH. Very enlightening SEM images and EDX analysis of the solids formed show a complex interaction between the scale inhibitor, zirconium concentration and pH.
The lessons learned from this development and case history will provide invaluable insights into the development of future fracture fluid packages, which are needing higher amounts of scale inhibitor as fracturing is occurring in more saline, higher temperature and pressure shale plays.
The Johan Sverdrup Field – Origin of Sulphate-Rich Formation Water and Impact on Scale Management Strategy
Authors: Ramstad Kari , McCartney Ross , Aarrestad Henriette Dorthea , Lien Siv Kari , Sæther Øystein , Johnsen Rita Iren 
Published: April 2016

Abstract
The Johan Sverdrup field will at maximum production contribute 25% of total oil production from the Norwegian continental shelf. Geochemical formation water interpretation and development of a scale management strategy have been performed to ensure high well productivity and process regularity of the field.
Uncertainty in the formation water compositions challenged the decision to inject normal seawater or low sulphate seawater into the reservoir for pressure support. Water compositions in samples obtained from appraisal wells were unusual for the Norwegian North Sea, being sulphate-rich with negligible barium. This was suspected to be an artefact of drilling fluid contamination and corrections were applied to obtain representative estimates. These confirmed that the formation waters had variable salinity (21–48 g/L chloride), and were indeed sulphate-rich (94–746 mg/L) and barium-depleted (&lt;6 mg/L). The compositions may reflect (a) mixing of formation waters across the field over geological time and (b) interactions with the underlying Zechstein Group (anhydrite). The focus here is on issue (b), as a detailed evaluation of local/regional aquifer movements in geological time, communication patterns and flow restrictions is beyond the scope of this paper.
Three appraisal wells in the Geitungen Terrace showed barium-rich formation water outside the main reservoir area where no underlying Zechstein Group was present. Initially, there were concerns about the scaling risks associated with mixing sulphate- and barium-rich formation waters. However, present geological understanding indicates insignificant aquifer volumes with barium, implying that full field development and scale strategy do not need to consider barium-rich water.
Scale predictions were performed for various strategies; formation water production, seawater injection, produced water re-injection and low salinity/low sulphate water injection. Moderate strontium sulphate (SrSO4) and calcium carbonate (CaCO3) scaling are expected in the production wells. If third party barium-rich waters are tied-in, the topside barium sulphate (BaSO4) scaling risk increases.
This work has shown: Careful evaluation of formation water samples/analyses reduces uncertainties associated with water compositions and increases confidence in results and decisions.Underlying geology can influence formation water compositions.Good quality water sampling is important for later phase field development and scale management.
The implications for field development are: Seawater will be injected into the reservoir for pressure support with no need for sulphate removal plant.Produced water re-injection will gradually replace seawater to minimize environmental impact.Downhole scale inhibitor injection has been recommended to protect the upper completion.
A Novel Delivery Method for Combined Scale Dissolver and Scale Squeeze Treatments in Non-Isolated Subsea Wells
Authors: Marinou Eugenia , de Boer Sarah , Chen Tao , Alexander Peter , Brady Ronan , Quirke Alan 
Published: April 2016

Abstract
The Chestnut field produces from two subsea, non-isolated commingled wells tied back to the Hummingbird FPSO. A steep decline in production was observed in Q1 of 2014 in well 22/2a-11x which was attributed to the formation and deposition of barium sulphate scale in the well and confirmed through a new method developed for the determination of seawater breakthrough onset in commingled wells (Chen 2015).
Following this, an elevated temperature barite dissolver treatment was designed so as to try and remove the scale and allow for a subsequent scale squeeze treatment to be applied. Deployment of the dissolver and scale squeeze treatments, however, presented several challenges, the main one being that the 22/2a-11x well cannot be mechanically isolated from the other well in the field for a treatment to be bullheaded. In addition, the common flowline was known to contain sand and the well's xmas tree design and vicinity to the FPSO meant that any chemical treatments needed to be delivered down the production riser; the limited deck space on the FPSO rendered this a particularly complex operation.
A supply vessel had to be modified to accommodate mixing, storing and heating capabilities, with heated dissolver being transferred to the FPSO via a suitably rated hose over open water. A unique delivery approach was developed to allow the successful placement of the scale dissolver and scale squeeze treatments in well 22/2a-11x through the use of a non-aqueous liquid "plug" in the common flowline; the combined treatments led to a doubling in the well's production compared to oil rates prior to the intervention.
This paper presents the difficulties associated with delivering these multistage treatments and the applied engineering solutions that enabled effective placement of both the scale dissolver and scale squeeze in this subsea well. In addition, lessons learned in the process as well as an evaluation of the placement strategy on the efficiency of the scale removal and squeeze treatments will be discussed.
Mixed Salt Scaling in Porous Media Due to Water Incompatibility: An Experimental Investigation
Authors: Zohoorian A. H. , Moghadasi J. , Abbasi S. , Jamialahmadi M. 
Published: April 2016

Abstract
Water injection is applied as a well-established process in different reservoirs for pressure maintenance and oil recovery enhancement in the petroleum industry. Scale formation is a common challenging issue in the water injection process. In this paper, mixed salt scaling, especially that of the typical sulfate salts, is studied.
Scale formation is resulted from incompatible interactions between the injection and formation water. Precipitation of the unwanted solid materials on a surface is responsible for some problems as the formation damage, and short life of the completion equipment and surface facilities. In this experimental study, through static and dynamic tests, co-deposition of various salts during water injection is examined. Static tests are performed so as to obtain properties of the mixed salt precipitation. Further dynamic tests are conducted with different variables like the pressure, temperature, concentration, and the degree of salinity.
Several studies conclude that the success of the water injection process is mainly dependent on both fluid-rock and fluid-fluid interactions. They have also mentioned the coexistent precipitation of the salts in the water systems; nevertheless, the referred studies focus on the single salt than mixed salts due to the complexity of the process. Permeability reduction is affected by different parameters such as the mixing ratio of the injected water to the formation water, concentration, salinity, temperature, pressure, pH, and injection rate.
This research is carried out in realistic conditions so that the permeability reduction is precisely and appropriately measured by well-designed equipment. This study considers the mixed salt composition which could give a better insight into the permeability reduction than the former works, especially those which only investigated the single salt scaling. At last, a better understanding of the mechanism of inorganic scale deposition on the rock surface is provided.
The Effect of Chelating Agents on the Use of Produced Water in Crosslinked-Gel-Based Hydraulic Fracturing
Authors: Elsarawy Ahmed M. , Nasr-El-Din Hisham A. , Cawiezel Kay E. 
Published: April 2016

Abstract
Hydraulic fracturing operations require large amount of water which, in some cases, could reach six million gallons per treatment. Fresh water, from surface and subsurface sources, is usually used to formulate the fracturing fluid. The use of produced water in hydraulic fracturing has gained increased attention in the last few years, as it would solve fresh water acquisition challenges and reduces its disposal costs. However, produced water usually contains high amounts of total dissolved solids (TDS) that prevents its compatibility with fracturing fluid additives and negatively affects the fracturing fluid rheology. This paper investigates the effect of different chelating agents on the use of high-TDS produced water in high pH borate-crosslinked gels used in hydraulic fracturing fluids.
Samples of field-produced water were analyzed for different ion concentrations. Synthetic water was prepared with different amounts of Na, K, Ca, and Mg salts. The fracturing fluid was formulated using natural guar polymer, borate-based crosslinker, biocide, surfactant, clay controller, scale inhibitor, and pH buffer. Five chelating agents tested in this study included HEDTA, GLDA, di-sodium EDTA, di-ammonium EDTA, and sodium gluconate. Compatibility tests of the fluid system at 180ºF were conducted at different ion concentrations. Apparent viscosity of the fracturing fluid was measured using a high-pressure high-temperature rotational rheometer. All rheology tests were conducted at a temperature of 180ºF and were conducted according to API 13m procedure with a three-hour test duration.
Results indicated the potentiality of high-TDS water to cause precipitate and, hence, formation damage. However, the use of chelating agents has reduced the precipitation of divalent cations and enabled the formulation of fracturing fluid at higher Ca and Mg concentrations. The use of 2.5 wt% of HEDTA has enabled the formulation of the fracturing fluid using synthetic produced water that contains TDS of 101,000 ppm with Ca and Mg concentrations of 2,500 and 200 ppm, respectively. The fracturing fluid showed an average viscosity of 150 cp at 100 s-1 despite the high-TDS and high-hardness environment. The use of GLDA reduced the Ca and Mg ion precipitation; however, its chelation effect was found to be limited to certain concentrations. Some chelating agents showed the ability to chelate the boron ion and/or reduce the system's pH value. Consequently, viscosity measurements indicated the breaking of the fluid viscosity after the addition of the chelating agent.
This paper presents the use of chelating agents to maximize the effectiveness of produced water for hydraulic fracturing operations. Successful use of chelating agents would reduce produced water disposal costs and improve the environment by reducing the consumption of fresh water.
Optimization of Huff-n-Puff Gas Injection to Enhance Oil Recovery in Shale Reservoirs
Authors: Li Lei , Sheng James J. , Sheng Jie 
Published: April 2016

Abstract
When the oil price is low, it is essential to optimize an EOR process in low-permeability reservoir, especially in unconventional shale oil reservoirs. Gas huff-n-puff, has shown to be an effective EOR method. This paper is to optimize this process to enhance oil recovery in shale oil reservoirs.
To optimize the huff-n-puff process, we need a field model. However, such field data were not available to us. In this paper, we first upscale laboratory-scale data to field-scale. In the laboratory, methane huff-n-puff experiments were conducted using the Wolfcamp core plugs with the same length of 2″ and different diameters (1.5″, 2″, 3″ and 4″) at injection pressure of 2000 psi. The cores were saturated with the Wolfcamp crude oil. A composition model was built to history match the experimental data. Then the model was scaled up to a field-scale model for the optimization study. The study is to optimize: 1) gas injection time and injection rate; 2) gas production time and production rate; 3) soaking time; 4) gas injection pore volume.
The simulation results show that the most effective optimization is to increase the pressure gradient during huff and puff periods so that the maximum average pressure gradient in the matrix can be achieved at a fixed operation time. The pressure gradient is increased by increasing injection pressure or decreasing production pressure. Before reaching the set injection pressure or production pressure, the oil recovery in one huff-n-puff cycle increases, as the injection and production times are increased. After reaching the set injection pressure and production pressure, increasing the huff or puff time will not lead to a significantly more oil recovery. There exist optimum values for injection rate during huff process and production rate during puff process. When the rate is less than the optimal value, the oil recovery increases as the operation rate increases. When the operation rate is higher than the optimal value, increasing the injection rate will lead to slightly decline in the oil recovery, while further increasing production rate will cause insignificant oil recovery increase. We also found that adding soaking time will decrease oil recovery.