bluuebunny/crossref_metadata_2025_split huggingface dataset:
New Compounds for Hydrogen Sulfide Scavenging and Iron Sulfide Control
Authors: Aften Carl W. , Roberts Gayla 
Published: September 2011

Abstract
New compounds have demonstrated effective scavenging of hydrogen sulfide with potential for preventing deposition of metal sulfides. These compounds come from a variety of functional families and compete against typical scavenging technology well with respect to molar efficiency, reaction rate, and stability. These inhibitors not only work on existing sulfide but some can also be modified to change the oxidation state of the system to provide a non-scaling scenario.
The presence of hydrogen sulfide is an ever increasing problem in the oilfield, whether the origin is biological or formation dependant. The presence of extremely toxic hydrogen sulfide increases the corrosion rates of many metals and makes necessary the sweetening of produced hydrocarbon. If solubilized metals such as iron, lead or zinc are present in the fluid, the deposition of sulfides may occur as flow restrictive scale on the tubulars, leading to corrosion and/or biofilm augmentation or formation damaging fine particulate in the pay zone.
These single component inhibitors were tested in standard synthetic formation waters which were either sulfide laden and/or metal or sulfide laden. Waters derived were standard unadulterated species at various pHs or were acidified and then spent on carbonate. The rate of sulfide uptake was monitored and the soluble metal ions were determined. Response surfaces were generated for a few key inhibitors and the performance of the inhibitors was compared to standard inhibitors. Stability was also checked to ensure insoluble or reversible scavenging species were measured.
The use of these scavengers for drilling, stimulation, completion, and produced fluids provides the service company and/or operator with a viable treatment for problems incurred when treating sour reservoirs.
An Experimental Study of a New VES Acid System: Considering the Impact of CO2 Solubility
Authors: Gomaa Ahmed M. , Wang Guanqun , Nasr-El-Din Hisham A. 
Published: September 2011

Abstract
Viscoelastic surfactant (VES) based self-diverting acid system has been developed for better matrix treatment of carbonate formations. Literature survey indicates that the highly viscous fluid acts as a temporary barrier to reduce further fluid loss into the wormholes and allows complete stimulation of all treating zones. After acid treatment, the viscous fluid is broken by either formation hydrocarbons or pre-flush fluids. However, recent lab work confirmed that a significant amount of surfactant was retained inside the core even when mutual solvent was used. The present study was conducted to better understand these acid systems and determine factors that impact their viscosity build-up and performance inside the carbonate formations.
A series of coreflood tests were conducted using low and high permeability carbonate cores at different injection rates. Propagation of the acid, surfactant, and reaction products inside the cores was examined in detail. Samples of the core effluent were collected and the concentrations of calcium, surfactant, and acid were measured. Permeability enhancement and location of any precipitation was detected using CT scanner to the core before and after the acid injection. Material balance was conducted to determine the amount of surfactant that retained in the core.
Experimental results show that VES acid was only able to build pressure drop across the core at injection rates less than 1 cm3/min when it was injected inside 80 md permeability cores. However, at injection rates of 1 cm3/min and higher, VES was not able to build any pressure drop across the core when it was injected into 4 md cores. Acid pore volume to breakthrough and amount of VES retained in the core were reduced when low permeability cores were used. Calcium propagated faster than HCl, while surfactant propagated the same rate as HCl. Also, pore volume needed to breakthrough the calcium and the maximum calcium concentrations were independent of the acid injection rate. CT scan confirmed that wormhole branches were observed at the second half of the core. At ambient conditions: viscosity of live VES acid was higher than that of partially neutralized (pH 4.5). At temperatures greater than 140oF, the viscosity of partially neutralized acid was higher than the live acid. G’ of the live VES acid was dominant at ambient temperature, while when temperature increased to 85oF, G"became the dominant characteristics of the live VES acid.
Study of CO2 Effect on Asphaltene Precipitation and Compositional Simulation of Asphaltenic Oil Reservoir
Authors: Choiri M. , Hamouda A. A. 
Published: September 2011

Abstract
At pressures greater than the minimum miscibility pressure (MMP), oil and CO2 are mutually soluble. The dissolved CO2 reduces the viscosity of the oil and causes swelling of the oil phase, hence improving its ability to flow through the reservoir rock. As a mean of reducing emission CO2 is injected into mature reservoir for both sequestration and EOR. In cases where asphaltene is present both processes are affected.
The study here addresses asphaltene precipitation due to pressure, temperature and composition changes during CO2 injection into of asphaltenic oil reservoirs. It is, therefore imperative to identify stability conditions of the asphaltene.
A simple model approach has been developed in this work to determine the asphaltene stability envelope associated with CO2 injection. The model approach is based on Flory-Huggins polymer-solution theory and Hildebrand solubility concept. The model approach is verified by literature data from different crude oil compositions.
In addition a simulation work, by compositional simulator, is done to map the asphaltene deposition within a reservoir, which that confirmed our previous study where it is demonstrated the dependence of asphaltene precipitation on the magnitude of the pressure drop within the production area of the reservoir.
Optimized HP/HT Acid Blends and Associative Polymer Diversion Proven to be Successful in Acid Fracturing a Multilayered Reservoir: A Case History from South Ghawar Gas Field in Saudi Arabia
Authors: Solares J. R. , Al-Asiri Khalid , Franco Carlos , Vielma Jose , Izquierdo Guillermo 
Published: September 2011

Abstract
Acid fracturing has been extensively used as a well proven method to stimulate carbonate formations in the Ghawar field. The unique reservoir characteristics found in all the wells producing from carbonate reservoirs in the field make acid fracturing stimulation operations highly dependent on fracture stimulation capability to connect multilayered zones, adequate fluid efficiency (effective leakoff control), fluid properties to generate proper fracture geometry with high-pressure/high temperature environments, and engineering work to design an economical but successful stimulation treatment.
This paper discusses a case study for a gas well in a carbonate reservoir in Saudi Arabia where an effective diversion technique with associative polymers and new optimized acid formulations was successfully performed. The treatment included a delayed borate crosslinked fluid used as a pad to create and extend the hydraulic fracture, and two 26% hydrochloric (HCl) acid blends (one emulsified and the other gelled) to efficiently penetrate and etch the surface rock. Also, proper diversion stages were included to ensure full stimulation zonal coverage, and rigorous engineering efforts to ensure that an economical but successful acid fracturing stimulation treatment could be performed.
Both the emulsified and gelled 26% HCl acid blends used were extensively tested for corrosion at a temperature of 275 °F. Additionally, emulsion stability tests were carried out on the mixtures to ensure retardation properties at bottom-hole conditions, and achieved a longer acid fractured etched length with optimum conductivity. Based on lab results, a new optimized emulsified acid formulation was finally designed and implemented.
The paper also summarizes the main results obtained when the previous optimized acid stimulation system was carried out in a highly deviated well. The final gas production results exceeded expectations, thereby confirming the effectiviness of a special acid blend for stimulation of carbonate formations.
Determining Microbial Activities in Samples from the Shale Gas Field Compromising Water Reuse and Disposal
Authors: Agrawal A. , Chatterjee I. , Voordouw G. , Lomans B. P. , Kuijvenhoven C. , Henderson J. 
Published: September 2011

Abstract
Gas production from subsurface shales requires fracture technologies in which fracturing fluid, consisting of guar gum-suspended sand, is forced into the fractures to "prop" them open. The guar gum is easily degraded by bacteria both downhole and at the surface, compromising water reuse or disposal. Samples from the Pinedale shale gas field had high activity of mesophilic acid-producing bacteria (APB), converting guar gum to sugars and then to acetic and propionic acids and of heterotrophic nitrate-reducing bacteria (hNRB), using sugars or acids from guar gum as electron donor for nitrate reduction. Activity of sulfate-reducing bacteria (SRB) was considerably lower with guar gum, reflecting a low initial population size of SRB using the organic acids produced by APB for reduction of sulfate to sulfide. The low concentrations of sulfate in the samples (0–0.4 mM; 0–40 ppm) may be the root cause for this low SRB activity. Indeed, most probable numbers (MPNs) of SRB, determined on standard lactate-sulfate medium were 10- to 100-fold lower than those for APB, determined on standard phenol red-glucose medium. Interestingly, lactate-utilizing SRB appeared to be able to grow in APB medium, indicating that some SRB can also maintain themselves by fermentative metabolism, when sulfate is absent.
Culture independent surveys of community composition confirmed that the microbial community at Pinedale samples was dominated by classes of fermentative bacteria (APB). Overall, we conclude that monitoring of the MPN of glucose-fermenting APB most accurately reflects microbial activity and associated biofouling at Pinedale. The success of biocide treatment to reduce microbial activity and associated biofouling is, therefore, also more accurately determined with the APB assay than with that for lactate-utilizing SRB.
Rheology of a New Sulfonic Associative Polymer in Porous Media
Authors: Seright R. S. , Fan Tianguang , Wavrik Kathryn , Wan Hao , Gaillard Nicolas , Favéro Cédrick 
Published: September 2011

Abstract
For hydrophobic associative polymers, incorporating a small fraction of hydrophobic monomer into an HP AM polymer can promote intermolecular associations and thereby enhance viscosities and resistance factors. In this paper, we investigate the behavior of a new associative polymer in porous media. The tetra-polymer has low hydrophobic monomer content and a molecular weight (Mw) of 12–17 million g/mol. Total anionic content is 15–25 mol%, including a few percent of a sulfonic monomer. This polymer is compared with a conventional HPAM with 18–20 million g/mol Mw and 35–40% anionic content. Rheological properties (viscosity versus concentration and shear rate, elastic and loss moduli versus frequency) were similar for the two polymers (in a 2.52% TDS brine at 25°C). For both polymers in cores with permeabilities from 300–13,000 md, no face plugging or internal filter cake formation was observed, and resistance factors correlated well using the capillary bundle parameter. For the HPAM polymer in these cores, low-flux resistance factors were consistent with low-shear-rate viscosities. In contrast, over the same permeability range, the associative polymer provided low-flux resistance factors that were 2–3 times the values expected from viscosities. Moderate shear degradation did not eliminate this effect—nor did flow through a few feet of porous rock. Propagation experiments in long cores (up to 157 cm) suggest that the unexpectedly high resistance factors could propagate deep into a reservoir—thereby providing enhanced displacement compared with conventional HPAM polymers. Compared with HPAM, the new polymer shows a significantly higher level of shear thinning at low fluxes and a lower degree of shear thickening at high fluxes.
Scale Formation Prevention During ASP Flooding
Authors: Karazincir O. , Thach S. , Wei W. , Prukop G. , Malik T. , Dwarakanath V. 
Published: September 2011

Abstract
The purpose of this work was to identify complexing agents and commercial scale inhibitors that can prevent scale formation in field brine during an ASP flood. The original field brine has near 1,000 ppm Ca++/Mg++ and 450 ppm HCO3− at pH 6 (Scale index, SI=0 at reservoir conditions). During ASP flooding, when the pH is increased to above 9, CaCO3 and MgCO3 scale occurs (SI=2.36). In order to prevent scaling during an ASP flood, divalent cations can be captured by addition of agents that form water-soluble complexes with metal ions in brine. With this purpose, six organic and two inorganic complexing agents as well as six different commercially available complexing agent brands have been tested. A working formulation with 11,000 ppm of an organic complexing agent was developed that can prevent scale formation up to pH values 10.5. The scale prevention capacity of four different commercial scale inhibitors were also tested alone and in combination with the mentioned complexing agents. Addition of 200 to 500 ppm of phosphonate or polyvinyl sulfonate based scale inhibitor helps drop the complexing agent concentration needed to prevent scale formation down to 5,500 ppm at pH values of 10.3 or less.
Minimizing Scale Precipitation in Carbonate Cores Caused by Alkalis in ASP Flooding in High Salinity/High Temperature Applications
Authors: Bataweel M. A. , Nasr-El-Din H. A. 
Published: September 2011

Abstract
Using an inorganic alkali in alkaline/surfactant/polymer (ASP) flooding resulted in scale precipitation when multivalent cations exist in mixing and/or formation brine in some extended field studies. This issue can be critical in the un-swept zones, which are the major target for EOR process, where formation brines can have high concentrations of Ca2+ and Mg2+. Any precipitation can result in plugging the pores in the target zone and loss of injectivity.
Several alkalis were evaluated to assess their scaling potential in high salinity formation brines and seawater as mixing brine at high temperatures. Four alkalis were evaluated; three inorganic alkalis sodium hydroxide, sodium carbonate, and sodium metaborate, and one organic alkali.
Eliminating the need to soften the mixing brine will result in expanding the ASP application to more challenging applications and will reduce the softening cost for the mixing water. Preventing precipitation of scale when chemical slug enters the unswept zones will result in improving the efficiency of the ASP flood, reduces chemical consumption and prevent scale precipitation that can cause formation damage and operational problems in the producers.
Split-Fluid Method Improves Fracturing Operational Efficiency
Authors: Mandarich Matthew , Neal Greg 
Published: September 2011

Abstract
Split-fluid fracturing uses two fluid streams, (1) a highly concentrated slurry and (2) a clean fluid, sent to separate groups of high-pressure pumps, which is an alternative to the traditional method of supplying a lower-concentration slurry to all highpressure pumps. Reducing the number of high-pressure pumps exposed to abrasive slurries extends pump and manifoldequipment life. Centrifugal pumps at the fracturing-fluid supply send water to the blender and also boost the clean fluid highpressure pumps directly. Chemical additives, such as friction reducers, can be added to the clean fluid. The highly concentrated slurry and the clean fluid are mixed together in the high-pressure manifold. The resulting fluid-proppant concentration is monitored by a high-pressure densometer. Updated blender operating software combines input from flow meters monitoring the two fluid streams to determine a real-time combined fluid rate. Chemical additive and proppant rates are adjusted by the blender software so that the combined fluid meets the fracturing job-design specifications. Field trials were conducted to determine the effectiveness of this method along with variations to the method, such as mounting the clean fluid-supply boost pumps onto the high-pressure manifold trailer.
This method has been successful in waterfrac market areas using low proppant concentrations (0.5-lbm/gal concentration on the majority of jobs), high water volumes (more than 3,000 barrels), and high-rate (more than 50 bbl/min) fracturing treatments.
Maintenance costs were dramatically reduced while fracturing treatments were delivered to the operator as designed with increased reliability of pumping equipment and no lost time.
Fracturing equipment service operators and well operators both benefited from reduced operational costs and the increased reliability of the pumping equipment. Additionally, reducing the amount of back-up fracturing equipment required helped reduce the equipment footprint on location.
Structural Integrity and Life Extension of Offshore Installations by Ultrasonic Peening
Authors: Martinez Luis Lopez 
Published: September 2011

Abstract
Extensive life extension studies for a FPSO installation have been carried out. High stressed welds showed too short fatigue lives in as-welded condition. Ultrasonic peening has been selected to extend the fatigue lives of the concerned weld details. The aim with the ultrasonic peening treatment was to avoid any further weld repair and by that contribute to the structural integrity of the installation during its remaining service life.
Fatigue life extension has been achieved by the application of ultrasonic peening to high stressed areas on the pallet stool- and on longitudinal-weld details on the ballast tanks on a FPSO installation.
The fatigue lives for the treated welds were extended to twenty years which is the targeted service life for the installation.
Quality Assurance and Quality Control were covered by Ultrasonic Peening Procedure Specification, applied for every treated weld. It ensures that the treatment is exactly reproduced to achieve the expected life extension.
Despite the variable weld quality encountered on the pallet stool welds the treatment was carried out at perfection and it showed to be relatively easy and straight forward application even in locations of difficult access.
The economical benefits due to reduced maintenance as a result of the ultrasonic peening treatment include:
Implementing a Novel Method for Injection Efficiency Optimization in Water Flooding Process: Case Study
Authors: Bostan Mashaallah , Kharrat Riyaz , Ghorbani Davood 
Published: September 2011

Abstract
The work has used a novel method for injection efficiency optimization following water flooding management in one of the Iranian under saturated oil reservoir. This reservoir is located at south west of Iran with 10km2 area, oil gravity 34° API, oil formation volume factor 1.45 bbl/STB, gas oil ratio 865 SCF/STB and initial pressure of 3200 psi.
This method is on the basis of individual streamline simulation ability, to describe Well Allocation Factor for injection and production wells. On the other hand, by using streamline simulation we can identify: 1) distribution of injected water to associated producers, 2) water loss to the aquifer, 3) percentage of oil produced due to each supporting injector, and 4) amount of water cut attributable to each supporting injector. Since the Well Allocation Factor provides the amount fluid attributed to each injector-producer pair, it is possible to define injection efficiency. The optimization of injection efficiency is based on increasing the injection rates in efficient injectors and decreasing them in inefficient injectors. In this study, therefore, we have used streamline simulation for injection efficiency optimization with the aim of increasing oil recovery. The current study includes 2 parts. Firstly, we identify wells injection rates based on mathematical relationships and secondly we increase injection efficiency and oil recovery by decreasing water loss to the aquifer. By using this method and with the same amount of injected water, in the first and second part injection efficiency increased from 46% to 53% and 53% to about 55% in a three years simulation respectively. At the end, it was revealed that this method is suitable to identify and optimize injection rates, reduction water loss to the aquifer and subsequently an increase in oil recovery.
Openhole Versus Cemented Completions for Horizontal Wells with Transverse Fractures: an Analytical Comparison
Authors: Augustine Jody R. 
Published: September 2011

Abstract
Horizontal wells that are to be stimulated with transverse fractures are usually completed either openhole with annular isolation packers or cemented. Fluid communication is established by perforating or using stimulation sleeves. The industry continues to grapple with several issues regarding these completions, such as what the optimum number of fractured intervals is, and which approach (openhole versus cemented) provides the best hydrocarbon production.
Analysis was performed to create a simple method for determining the production impacts of increasing the number of fractured intervals in a horizontal well. The intent was to create something similar to the McGuire-Sikora curves (method of determining the production impacts of fracturing vertical wells) for horizontal wells with transverse fractures. Using the McGuire-Sikora curves allows for a quick assessment of productivity gains associated with fracture stimulating a vertical well.
Analysis was performed using a two-dimensional reservoir simulator using a steady-state edge drive. A methodology was developed, and is described, for including the effects of vertical to horizontal permeability ratios in a two-dimensional simulator.
Analytical results showed productivity-index ratios as a function of relative conductivity for different fracture geometries. The resulting curves were used to estimate production gains of fracture stimulation compared to the openhole, unstimulated case. The variables included in the analysis were reservoir permeability, vertical to horizontal permeability ratio, reservoir thickness, reservoir length, fracture half-length, fracture width, fracture permeability, fracture spacing along the horizontal, and openhole and cemented completions.
In this paper, comparisons are made to published works that use production data and microseismic data to compare openhole and cemented completions. The analysis presented should help fuel the industry debate of whether cemented completions are an overused solution.