bluuebunny/crossref_metadata_2025_split huggingface dataset:
A New Organic Acid To Stimulate Deep Wells in Carbonate Reservoirs
Authors: Al-Douri Ahmad F. , Sayed M. A. , Nasr-El-Din H. A. , Aften Carl 
Published: June 2014

Abstract
Carbonate acidizing has been carried out using HCl-based stimulation fluids for decades. However, at high temperatures, HCl does not produce acceptable results because of its fast reaction, acid penetration, and hence surface dissolution, and its high corrosion rate. As a result, alternatives to HCl have been investigated including organic acids. In this work, the reaction of a new organic acid with calcite was investigated using the rotating disk apparatus and coreflood setup. The organic acid was obtained using both a phosphorous-based and iron-based catalyst.
The rate of reaction of a 10 wt% solution of the new organic acid was measured using the rotating disk apparatus at temperatures up to 250°F. Low-permeability Indiana limestone (1-5 md) samples of 1.5 in. diameter and 0.75 in. length were used. The effect of disk rotational speed (100-1,500 rpm) was investigated. Also, three coreflood experiments at an injection rate of 2.0 cm3/min and a temperature of 300°F were performed to study the effect of acid on the wormhole propagation in calcite. Low-permeability Indiana limestone (1-5 md) cores used in these experiments have a diameter of 1.5-in. and a length of 6 in. Samples of the reacted fluid were collected periodically and calcium and iron concentrations were measured using Inductively-Coupled Plasma, and used to determine the acid-rock reaction rate and to study the possibility of precipitation.
For the phosphorus-based acid, experimental results showed that the rate of calcite dissolution at 205°F was controlled only by the rate of mass transfer of the acid to the surface. However, at 250°F, the reaction was controlled by both mass transfer and by the kinetics of the surface reaction. At 205°F, the reaction rate varied from 7.79E-07 to 4.47E-06 gmol/cm2.s, while at 250°F, the range was between 5.82E-07 and 2.72E-06 gmol/cm2.s. In coreflood experiments, the phosphorus-based acid caused phosphorous precipitation at 300°F, while the iron-based acid achieved breakthrough. This paper summarizes the results obtained and recommends the use of the new organic acid for field applications in calcite reservoirs.
Use of Tracers To Evaluate and Optimize Scale Squeeze Treatment Design in the Norne Field
Authors: Vazquez O. , Mackay E. , Tjomsland T. , Nygard O. , Storas E. 
Published: June 2014

Abstract
When squeezing scale inhibitors into oil production wells the inhibitor should usually be uniformly placed in the open intervals to optimise squeeze lifetime. In wells with varying reservoir quality and/or significant cross flow, however, uniform placement is difficult to obtain. Flow diverters are frequently used to improve the chemical placement. In many cases it is of great interest to evaluate the squeeze performance and assess the actual placement and back production of inhibitor to gather well information and thereby be able to optimise the future squeeze designs. This can be particularly interesting in subsea wells where other kinds of data collection, such as production logging, is not feasible due to high intervention costs and high operational risk. This study suggests the use of tracers during squeeze treatments to evaluate the placement as an alternative to running PLT.
The main purpose of this paper is to demonstrate the applicability of tracers, in this particular study the injection of a KCl slug in a producer well in the Norne Field, to evaluate the layer flow rate profile along the completion interval, which depends on each layer's pressure and geological properties. The study consists first of verifying the layer flow rate profile predicted by a history matched reservoir model. Then based on this layer flow rate profile, a tracer injection programme was designed, which included two production stages at different rates. Finally, based on the reservoir model predictions it is identified that each layer is at different pressures, and this leads to a distinctive return profile.
To evaluate the match between the observed and the simulation data, the layer flow rate profile from the reservoir model was used to populate a specialized near wellbore model for scale squeeze treatments. The match between the simulated and the observed data was good. However, the near wellbore model, in particular the layer flow rate profile, was further fine tuned. Finally, the fine tuned near wellbore model was used to optimize future treatments more accurately with the fine tuned layer flow rate profile.
Laboratory Characterization of Gel Filter Cake and Development of Nonoxidizing Gel Breakers for Zirconium-Crosslinked Fracturing Fluids
Authors: Reddy B. R. 
Published: June 2014

Summary
Borate or Group 4 metal-crosslinked biopolymer fluids constitute the bulk of gelled-fracturing-fluid volumes used in field-fracture stimulation operations to date. Oxidizing chemicals remain the primary gel breakers to break down the filter cake and establish regained formation permeability or fracture conductivity. These breakers presumably oxidize the polymer backbone, causing chain breakdown and facilitating fluid flowback. Safety hazards associated with the use of bulk quantities are one of the many potential problems associated with the use of oxidizing agents as gel breakers. Proper timing of gel breakdown is of utmost importance with respect to oxidizing gel breakers. Conversely, premature polymer oxidation can cause premature proppant settling. On the other hand, a long delay between the completion of the fracturing operation and activation of the gel breaker could cause the deposition of additional filter cake on fracture faces, which could be difficult to break down. A desirable advancement of designing improved fracturing fluids is to develop nonoxidizing gel breakers that focus on decrosslinking the crosslinked gel structure by reacting with the crosslinking agent, rather than only breaking down the polymer chain. In addition, by insolubilizing such breakers, they can be embedded in the filter cake and, when activated, they can degrade the filter cake completely without leaving any residues.
In this paper, synthetic disks of different porosities were used to simulate formation-permeability damage caused by filter cakes formed by Zr-crosslinked, carboxylated guar-based gels, and the results were compared with those measured for uncrosslinked fluids. The filter cakes were formed under different applied-pressure regimes and characterized for their polymer content and filter-cake/filtrate-weight ratios. From flow-rate measurements, it was clear that uncrosslinked base polymer solutions did not cause any permeability damage. Uncrosslinked polymer fluids produced from Zr-crosslinked gels by use of decomplexing, nonoxidizer breakers also did not significantly damage disk permeability compared with the fluids produced from conventional, oxidizer-type breakers. Several ortho-disubstituted aromatic compounds containing polar heteroatoms capable of functioning as potentially strong ligands for zirconium were found to be suitable as decomplexing breakers. Biopolymers containing such functional groups, notably lignosulfonate derivatives, show promise as commercially viable alternatives to oxidizing breakers for metal-crosslinked fracturing fluids.
Activator Development for Controlling Degradation Rates of Polymeric Degradable Diverting Agents
Authors: Reddy B. R. , Cortez Janette 
Published: June 2014

Abstract
Hydrolytically degradable polymers (generally aliphatic polyesters) have been used in a variety of applications in the oil field, such as fluid diversion, fluid-loss control, and filter cake removal applications. In general, diverting agents and fluid- loss-control materials are only necessary to perform the intended function for a finite amount of time. Once the well is completed or placed on production, it is desirable that the degradable materials be removed so that they no longer have any influence on subsequent fluid flow. With time and temperature, the degradable polymers will break down by forming water- soluble byproducts, leaving behind limited, if any, residual formation damage. The effective formation sealing by these materials while in place, and eventually during cleanup, has made them sought after for a growing number of applications. However, for cooler temperatures, and applications where the well must be placed on production more quickly, there have not been many options to controllably increase the rates of polymer degradation. This has considerably limited the realization of the full potential of the technology. There is an increasing demand for faster cleanup of the diverting agents and fluid-loss- control agents for applications at cooler temperatures.
Strong acids and bases are known to accelerate the degradation of these polymers. Use of such materials can present several disadvantages, such as corrosion and/or undesirable reactions with the formation. Although enzymes are used for the activation of ester hydrolysis, the use of enzymes has not demonstrated effectiveness in all situations. There is a need for chemical activators that can controllably accelerate the degradation of polymers at wellbore temperatures without the detrimental effects of using strong acids or bases. This paper discusses specific activators that can degrade various types of polymers and polymer blends containing degradable functional groups in the polymer backbone. The polymers tested in this study had variable crystallinities and chemical compositions. This paper also presents a new approach to degradation activation that should be more desirable in oilfield applications where the degradation times can be controlled for wide range of temperatures and wellbore conditions.
Experimental Investigation and Correlation of Thermal Effects on Near-Wellbore Formation Treatment by Gel Particles
Authors: Al-Ibad Adnan , Civan Faruk 
Published: June 2014

Abstract
The plugging and permeability impairment processes involved in the treatment and conditioning of high permeability porous formations is investigated at various temperatures by flowing of a suspension of gel particles through unconsolidated proppant packs. The permeability reduction and resistance factor are inferred by measurements of the pressure differentials with time across the proppant pack. Temperature effect is observed to be an important factor in suspended gel treatment of high permeability near-wellbore zones because temperature affects the gel properties and placement rate processes significantly. The effective mechanisms of the consecutive plugging and unplugging processes occurring during the flow of gel particles suspension through the proppant pack are identified and the best-estimate values of their rate coefficients are determined. The laboratory measurements of the viscosity, differential pressure, permeability reduction, and resistance factor are correlated successfully as functions of temperature. Various empirical correlations of practical importance developed in this work can be used for effective design of the suspended gel particles treatment in weak and highly permeable near-wellbore formations. These correlations can predict the effect of temperature on conditioning of the high permeability and weak formations by injection of suspension of gel particles.
Evaluation of Environmentally Acceptable Surfactants for Application as Flowback Aids
Authors: Galindo Tanhee , Rimassa Shawn 
Published: June 2014

Abstract
Recovery of injected fluids from aqueous hydraulic fracturing applications can be enhanced by the use of flowback aids. These additives are typically surfactants or co-solvents that reduce capillary pressure and water blocks. A range of different types of flowback aids, which contain water-wetting nonionic to amphoteric and oil-wetting components, are commercially available for use in hydraulic fracturing applications.
This paper evaluates various environmentally acceptable non-ionic and anionic surfactants for application as flowback aids in hydraulic fracturing applications. Fluid recovery was increased significantly with different alkyl polyglucosides and alkyl ethoxylates. Fluid recovery could be improved from 10% with base fluid up to 89% with the addition of a surfactant. Performance in fluid recovery corresponds best with surface tension data and capillary pressure reduction data, calculated from the surface tension and contact angle. Contact angle measurements alone cannot be used as screening tools for flowback aid evaluation.
Heightened concerns about the environmental impact of chemical additives used in fracturing fluids along with new and pending environmental requirements have led to a demand for chemistries with reduced environmental impact. Products tested meet or exceed U.S. Federal or state environmental chemical compliance guidelines.
Improving Oil Recovery In Gas-flooded, Oil-wet Carbonate Reservoirs by Wettability Altering Surfactants
Authors: Wang Leizheng , Mohanty Kishore K. 
Published: June 2014

Abstract
Carbonate reservoirs have complex pore structure and tend to be oil-wet. The remaining oil saturation is often high after a gas flood. The goal of this work is to develop and evaluate surfactant formulations that can improve the oil recovery after a gas flood. An anionic surfactant was used to develop a low IFT and wettability altering formulation for a soft injection brine and EDTA was added to modify the formulation for a hard injection brine. These surfactant solutions changed the wettability of an oil-wet calcite plate to intermediate-wet/water-wet conditions. Core spontaneous imbibition tests and corefloods were conducted. These displacements were simulated using CMG-STAR to study in-situ viscous fingering during gas injection and improved oil recovery using surfactant formulations. The hard brine surfactant formulation recovered 54% of the original oil in 60 hours by spontaneous imbibitions compared to 12% for the soft brine surfactant formulation and no oil for the formation brine. Initial gas flood left a lot of oil unswept. EDTA assisted hard brine surfactant formulation could recover over 40% of the oil, higher than 25% for the soft brine surfactant formulation. The gas injection after the surfactant slug increased the pressure drop due to foam formation. Numerical simulation of the GSG flood showed in-situ viscous fingering during the first gas injection and efficient oil displacement during the surfactant injection and the subsequent gas injection.
A New Finding in the Interaction Between Chelating Agents and Carbonate Rocks During Matrix Acidizing Treatments
Authors: Assem A. I. , Nasr-El-Din H. A. , De Wolf C. A. 
Published: June 2014

Abstract
During matrix acidizing, successful iron control can be critical to the success of the treatment. Iron (III) precipitation occurs when acids are spent and the pH rises above 1, which can cause severe formation damage. Chelating agents are used during these treatments to minimize iron precipitation.
In this paper, we studied the effect of iron precipitation in acidizing operations. HCl solutions (5 - 20 wt%) containing 5,000 to 10,000 ppm of Fe3+ were used in these experiments. Biodegradable GLDA (glutamic-N, N-diacetic acid) was studied in the experiments. The effect of varying acid concentration and chelate-to-iron mole ratio was examined. Coreflood experiments were conducted on low permeability Indiana limestone (1 - 5 md) at 200°F. The cores were scanned after treatments using a CT scanner. The core effluent samples were analyzed for total iron and calcium concentrations using ICP-ES. A calcium ion-selective electrode was used to determine the concentration of free calcium ions, i.e. calcium ions not complexed by the chelate, in the core effluent samples.
Results showed that the amount of iron recovered depended on both chelate-to-iron mole ratio and the initial permeability of the cores. Calcium is chelated along with iron, which limits the effectiveness of chelating agents to control iron (III) precipitation. Chelating agents are supposed to control iron now that calcium is also chelated, this amount should be accounted for. Acid solutions should be designed considering this important finding for more successful treatments. This paper will discuss the results obtained and give recommendations to enhance the effectiveness of these chemicals in the field.
The Formation and Chemical Nature of Amorphous Dithiazine Produced From Use Of Hexahydrotriazine Based Hydrogen Sulfide Scavengers and the Use of an Alternative Scavenger to Minimize Solid Formation in Sour Gas Applications
Authors: Taylor Grahame N. , Prince Philippe , Matherly Ron , Ponnapati Ramakrishna , Tompkins Rose , Panchalingam Vaithilingam , Jovancicevic Vladimir , Ramachandran Sunder 
Published: June 2014

Abstract
The most commonly used hydrogen sulfide (H2S) scavengers, hexahydrotriazines, are cost effective, efficient solutions to sour gas treatment. As the product consumes H2S and the by-product concentration increases, very often solid deposits occur, the most problematic of which is "amorphous dithiazine". It is produced from a solution of, for example, tris-(2-hyroxyethyl)-hexahydro-s-triazine. Recent findings have confirmed that this material is not a different physical form of the monomeric dithiazine but rather a polymeric structure which results from opening of the dithiazine ring. Evidence is presented here for the first step in this polymerization reaction. Thereafter, a ring opening of the dithiazine occurs to yield a polymeric, highly insoluble material. It has been observed that the critical chemical species in the initiation of this chain reaction is the bisulfide anion that is produced from the reaction of H2S with ethanolamine liberated in the sulfur insertion reaction undergone by tris-(2-hyroxyethyl)-hexahydro-s-triazine. This process has been artificially induced by the reaction of monomeric or crystalline 5-hydroxyethyl dithiazine and ethanolammonium hydrosulfide. It is hoped that a better understanding of the chemical process giving rise to this intractable solid will enable more efficient, environmentally favorable disposal of the waste fluids and, at best, total avoidance of this undesirable condition.
A novel approach to address this issue of troublesome solids, the use of an alternative scavenger type, is presented in this paper. The disposal of the waste fluids was a key issue in our consideration since the disposal of spent triazine based scavenger fluids is becoming ever more challenging and costly. Scaling tendencies at high pH is another issue for any new scavenger and plays a key role in the method of waste fluid disposal. Recent field trial data are also presented to demonstrate the efficacy of the new scavenger.
Integrated Rock-Typing with Capillary Pressure Curve Clustering
Authors: Fournier Frédérique , Fabre Gilles , Aug Christophe 
Published: June 2014

Abstract
This paper proposes a new methodology for an automatic classification of capillary pressure curves in order to build petrophysical rock-types which, in a second step, are compared to lithofacies for ensuring consistent and significant connection between lithological and petrophysical characteristics. The methodology is based on a pattern recognition strategy, where the curves to be classified are described by a certain number of features. In our approach, the features are derived using a principal component analysis applied to the series of capillary pressure curves under analysis. They correspond to the correlation coefficients of the principal components with the curves that should be classified. Other types of curves could be classified with this approach, for example curves of pore size distribution. This methodology is discussed through an application to the rock-typing of a clastic reservoir, and it is shown that relevant rock-types were obtained based on this classification approach. It is also shown that the classification helps in better quantifying the correspondences between the rock-types and the lithofacies.
A Novel Infinite-Acting-Radial-Flow Analysis Procedure for Estimating Permeability Anisotropy From an Observation-Probe Pressure Response at a Vertical, Horizontal, or Inclined Wellbore
Authors: Onur M.. , Hegeman P.S.. S. , Gök I.M.. M. 
Published: June 2014

Summary
This paper presents a new infinite-acting-radial-flow (IARF) analysis procedure for estimating horizontal and vertical permeability solely from pressure-transient data acquired at an observation probe during an interval pressure-transient test (IPTT) conducted with a single-probe, dual-probe, or dual-packer module. The procedure is based on new infinite-acting-radial-flow equations that apply for all inclination angles of the wellbore in a single-layer, 3D anisotropic, homogeneous porous medium. The equations for 2D anisotropic cases are also presented and are derived from the general equations given for the 3D anisotropic case. It is shown that the radial-flow equation presented reduces to Prats' (1970) equation assuming infinite-acting radial flow at an observation point along a vertical wellbore in isotropic or 2D anisotropic formations of finite bed thickness.
The applicability of the analysis procedure is demonstrated by considering synthetic and field packer/probe IPTT data. The synthetic IPTT examples include horizontal- and slanted-well cases, but the field IPTT is for a vertical well. The results indicate that the procedure provides reliable estimates of horizontal and vertical permeability solely from observation-probe pressure data during radial flow for vertical, horizontal, and inclined wellbores. Most importantly, the analysis does not require that both spherical and radial flow prevail at the observation probe during the test.
Kashagan Field Approaching Production Start-Up: Insight Into Reservoir Characteristics
Authors: Albertini C. , Bado L. , Calabrese M. , Francesconi A. , Leoni G. , Tarantini V. 
Published: June 2014

Abstract
Since field discovery, several studies have been performed in order to estimate the reservoir characteristics. In fact data collection has allowed a better understanding of this complex carbonate reservoir, although uncertainties still remain. The first step of production ramp-up will achieve 180,000 stb/d, actually constrained by the gas handling capacity. The production will be delivered by wells located in the D and A islands, whose potential exceeds this production target. Platform Interior wells performance has been defined through a Reservoir-Rock-Type petro-physical characterization matching well test data while Rim wells, characterized by outstanding performances, have been modeled trying to represent the very complex framework constituted by rock-matrix, karst features and fractures. The second ramp-up at 370,000 stb/d will be achieved by the expansion of the gas handling capacity through the start of gas injection applied to the Platform Interior. This phase will rely on the conversion of four D island producers into injectors: their injectivity will be affected by the maximum gas injection pressure, constrained by the cap-rock integrity and the reservoir pressure draw-down achieved during the initial pre-depletion. The gas injection effectiveness will be affected by Platform Interior heterogeneity and by the possible presence of a fracture network. Next development steps will be influenced by the Rim connectivity, actually not well understood.