Objective. Ankylosing spondylitis (AS) diagnosis is often delayed. The availability of effective biologic agents for treating AS has increased the importance of early diagnosis. We tested questions derived from a comprehensive literature review and an advisory board in a case-control study designed to identify patients with AS from among patients with chronic back pain (CBP). Methods. Question items were cognitively tested among patients with AS, and then in case-control studies for validation and creation of a scoring algorithm and question item reduction. AS cases were recruited from a known database, and CBP subjects (controls) were recruited from clinics, employers, and from the SpineUniverse Web site. We used individual question items in a multivariate framework to discriminate between people with and without AS. Results. Forty-three questions yielded 24 items for analyses; 12 of these were entered into a multivariate regression model. Individual items yielded odds ratios ranging from 0.07 to 30.31. Question items with a significant positive relationship to AS included male sex, neck or hip pain/stiffness, longer pain duration, decreased pain/stiffness with daily physical activity, pain relief within 48 hours of nonsteroidal antiinflammatory drugs, and diagnosis of iritis. The tool demonstrated a sensitivity of 67.4 and a specificity of 94.6. The tool was developed from clinically and radiologically diagnosed AS cases and therefore is designed to distinguish AS cases among CBP subjects. In addition, ϳ54% of the AS cases in the study were treated with biologic agents, which may impact questionnaire responses. Conclusion. This tool can identify undiagnosed patients with AS and, potentially, those at an earlier stage in their disease course.

Iron sulfide is a common scale-formation in sour-gas wells that restricts tubular diameter, reducing well productivity. Compared to other scales, iron sulfide has unique risks associated with chemical removal. For example, due to the corrosiveness of hydrochloric acid (the most common chemical agent for both sulfide and carbonate scale removal), damage to the completion metallurgy at elevated temperature limits its applicability. Another main concern related to the use of acid for iron sulfide removal is the rapid generation of H 2 S byproduct and the risks associated with production of this toxic gas to the surface.Owing to H 2 S toxicity and the resultant elevated corrosion risk, new chemical solutions are needed for high-temperature FeS scale dissolution with low H 2 S generation. This study describes the development and characterization of a powerful noncorrosive solution for iron sulfide removal based on a chelating agent. Testing shows the fluid dissolution capacity under varied temperatures, scale-surface area, treatment fluid volume, and exposure time. Tests are also included showing the comparative benefits in dissolution capacity compared to other commercially used products such as diethylenetriaminepentaacetic acid (DTPA) and Tetrakis (hydroxymethyl) phosphonium sulfate (THPS). Finally, the mild-pH of the new chemical solution provides significantly lower corrosion rate.This work describes an altogether new family of chemicals for sulfide scale, providing high dissolution capacity, low corrosion rates, and limited generation of toxic H 2 S.

Summary Flowback aids are usually surfactants or cosolvents added to stimulation treatments to reduce capillary pressure and water blocks. As the stimulated gas reservoirs become tighter, the perceived value of these additives has grown. This value must be balanced with the cost of the additives, which can be significant in slickwater fracturing treatments. There is a range of different flowback additives containing water-wetting nonionic to amphoteric, microemulsion (ME), and oil-wetting components. Determining the best additive for a specific reservoir is not a simple matter for the end user, and the existing literature is full of conflicting claims as to which one is most appropriate. This paper compares four different flowback aids: ME, two waterwetting flowback additives, and an oil-wetting additive. Careful laboratory testing was conducted to evaluate surface tension and contact angle for each flowback aid, using the recommended concentrations. Imbibition and drainage tests were performed that allowed calculation of the capillary pressures for the three additives. Drainage tests were performed on 1- to 3-md and 0.1-md cores. Capillary-tube-rise testing was also conducted as a check of the coreflood testing capillary pressures. This provided several different methods to determine capillary forces for the flowback aids. In addition, fluid-loss testing was conducted to determine if the flowback additives could improve fluid loss. All the flowback aids demonstrated low surface tension (approximately 30 mN/m), but each was different in terms of surface wettability and adsorption in the rock. In all cases, the flowback aids reduced capillary pressure to similar levels 70% lower than water alone. One of the water-wetting additives had much stronger adsorption in the core material than the other additives. The ME and the oil-wetting additive had improved fluid loss in a fully formulated fracturing fluid. In spite of the low capillary pressures, the additives had little effect on cleanup or return permeability on cores greater than 1 md. There are several implications of these results for the operator. Different flowback additives have a tradeoff of properties, and depending on the reservoir, selecting one that leaves the formation with certain wettability may be advantageous. Our testing indicated that understanding the reservoir is important in selecting the appropriate flowback aid.

The fields of East Kalimantan, Indonesia contain several depleted gas zones of medium permeability (0.1 to 300 mD). Though the permeability is quite good for gas bearing formations, the majority of the wells targeting these sands have failed to produce at expected rates. In the 1980s, hydraulic fracturing was introduced to the area in an attempt to increase production. The treatments yielded limited success with many wells actually producing less after being fractured. This led operators in the area to believe that the formations could be water sensitive with damage from the injected fluids causing the poor results after fracturing. As laboratory testing has ruled out water-sensitive mineralogy, the suspected cause of damage has been attributed to a decrease in relative permeability to gas after the fracturing fluid has penetrated the pore throats (water block). The water block conclusion is supported by the low percentage of injected fluids that are returned after the treatment.In 2007, VICO performed four fracturing treatments using a conventional surfactant to aid in post-frac cleanup. Only 2 of the 4 wells that were fractured produced after the treatment. Again, a common problem between the wells was the poor return of treatment fluids during cleanout. The limited success of these treatments indicated the water block issue had not been resolved. After reviewing the results of the first four wells, three additional fracturing treatments were placed in similar reservoirs using a microemulsion additive instead of the surfactant. Though laboratory testing in cores between 1 and 8.5mD failed to show a significant difference between the microemulsion and surfactant, the wells fractured with the microemulsion additive consistently outperformed those fractured previously in terms of returned treatment fluids and incremental production. Paktinat et al. (2006) wrote that the use of fracturing fluids with microemulsion in unconventional tight gas reservoirs can help increase production by increasing the relative permeability to gas in the area surrounding the fracture. Our study shows that similar benefits can also be achieved in depleted gas reservoirs with permeabilities greater than 1 mD, even if the benefits can not be clearly demonstrated under laboratory conditions.

Flowback aids are usually surfactants or cosolvents added to stimulation treatments to reduce capillary pressure and water blocks. As the gas reservoirs being stimulated become tighter, the perceived value of these additives has grown. This value must be balanced with the cost of the additives, which can be significant in slickwater fracturing treatments. There is a range of different flowback additives containing water-wetting nonionic to amphoteric, microemulsion, and oil-wetting components. Determining the best additive for a specific reservoir is not a simple matter for the end user, and the existing literature is full of conflicting claims as to which one may be most appropriate. This paper compares four different flowback aids: microemulsion, two water-wetting flowback additives, and an oil-wetting additive. Careful laboratory testing was done to look at surface tension and contact angle for each flowback aid using the recommended concentrations. Imbibition and drainage tests were done, which allowed calculating the capillary pressures for the three additives. Drainage tests were performed on 1-3 and 0.1 mD cores. Capillary tube rise testing was also done as a check of the core flood testing capillary pressures. This provided several different methods to determine capillary forces for the flowback aids. In addition, fluid loss testing was done to determine if the flowback additives could improve fluid loss. All the flowback aids demonstrated low surface tension (~30 dyne/cm), but each was different in terms of surface wettability and adsorption in the rock. In all cases the flowback aids reduced capillary pressure to similar levels 70% lower than water alone. One of the water-wetting additives had much stronger adsorption in the core material than the other additives. The microemulsion and the oil-wetting additive had improved fluid loss in a fully formulated fracturing fluid. In spite of the low capillary pressures, the additives had little effect on clean-up or return permeability on cores above 1 mD. There are several implications of these results for the operator. Different flowback additives have a tradeoff of properties, and depending on the reservoir, selecting one that leaves the formation with certain wettability may be advantageous. Our testing indicated that understanding the reservoir is important in selecting the appropriate flowback aid. Introduction: Flowback aids should in theory be critically important in either moderate permeability reservoirs for oil or low permeability reservoirs for gas (tight gas or shale). It is conceptually intuitive to argue that reducing the capillary pressure of the fluid in the near fracture region should improve flowback of the fracturing fluid, and reduce the drawdown to produce. In practice it is understood that oil and gas reservoirs are very complicated in their wettability. Almost never are formations pure sandstone. Clays line the pores of most reservoir rock, and in the case of shale, an added complication is the hydrophobic kerogen partially lining the pore surface. Further, the presence of liquid hydrocarbons may adsorb and alter the wettability of the reservoir. These factors make it difficult without direct measurement to determine the inherent wettability of reservoir. The fact that the composition and surface of the reservoir are heterogeneous in three dimensions further complicates the analysis.