bluuebunny/crossref_metadata_2025_split huggingface dataset:
Biphasic Viscosity Reducers as Production Aids for Viscous Oil
Authors: Faust M. , Weathers Thomas 
Published: September 2011

Abstract
In this report, the development and field deployment of a novel biphasic viscosity reducer will be discussed as a means to enhance production and transport efficiency of high viscosity crude oils while reducing total operating expenditures. Standard flow aids target the root cause of inefficient fluid flow; drag reducers, for example, suppress the turbulence associated with flowing oil, while paraffin inhibitors and asphaltene inhibitors prevent wax crystal or asphaltene particle growth. Biphasic viscosity reducer chemicals target the bulk fluid properties of the crude oil, regardless of the source of viscosity, by dispersing oil into free water, creating a highly flow-able, low apparent viscosity, water external emulsion. Screening tests confirmed the capacity of certain polymers to emulsify heavy oils, with API gravities well below 20, as well as waxy crudes from different locations around the world into 20-25% water solutions, creating stable, water external emulsions. In all cases the emulsion exhibited significant levels of apparent viscosity reduction, generating improved flow- ability in a bench-top flow loop, as well as emulsion resolution under standard field separation conditions including heat and traditional emulsion breaking chemicals. The top-performing products were assessed in a full-scale field trial on a high wax crude oil, where the biphasic viscosity reducer chemical resulted in efficient pressure maintenance for the topsides flow lines over the span of the field trial, significantly reducing operating costs associated with pressure buildup in these lines. Throughout the period of chemical injection, no adverse effects on water quality or oil/water separation were observed at the separation battery.
Scale Inhibitor Application In Northern Alberta - A Case History of an Ultra High Temperature Scale Inhibition Solution in Fire Tube Heater Treaters
Authors: Wylde Jonathan J , Allan Keith , McMahon Jeff , Mayner Steve 
Published: September 2011

Abstract
This paper reports further work performed on a challenging scaling environment in Alberta. Scale was forming on the fire tubes of a series of heater treaters. Bulk fluid temperature was 110°C but skin temperature of the fire tubes was in excess of 450°C. This created an incredibly high scaling potential.
Previous work characterized the scaling on the tubes. This is briefly summarized with an update given on the continued success of this treatment, best practice monitoring results, and optimization. This current work describes the further investigation of the system scaling challenge. It was found that in solving calcite scaling, other scale forms became dominant such as siderite and silica scales. Furthermore, it was found that one of the root causes of scale build-up was the presence of EOR polymer in the produced water.
Laboratory work evaluated the incumbent program for efficacy against siderite scale precipitation using an anoxic test method. Work focusing on the glue-like EOR polymer build-up has also been described, including chemical mitigation and remediation methods. Results showed that the incumbent treatment, whilst optimal for calcite scale, was not optimized for the overall multiple scaling scenario. Furthermore, the EOR polymer fouling mitigation required a totally new and unique treatment approach.
A summary of the field application and results of the new chemical strategy has been given illustrating a clear step change in the frequency of fouling in the production system. The paper concludes with a critique of how the laboratory data was representative of the field application. A final hypothesis is discussed, suggesting that EOR polymer breakthrough was a significant root cause of scale deposition due to the ease of deposition in the process system. Subsequently, this proved influential on the deposition of mineral scale and other solid deposits.
Case Study: Evaluation of an Oxidative Biocide During and After a Hydraulic Fracturing Job in the Marcellus Shale
Authors: Rimassa Shawn M. , Howard Paul , MacKay Bruce , Blow Kristel , Coffman Noel 
Published: September 2011

Abstract
Effective microbiological control is an important aspect of a successfully executed fracturing job. Control of bacterial growth is often accomplished through the use of biocides such as glutaraldehyde, particularly in the multi-stage, high-volume fracturing of unconventional shale gas reservoirs. Biocidal additives, which are toxic by necessity, can persist in flowback water, so their use in shale fracturing has come under increasing scrutiny since high biocide concentrations in flowback water increase fluid cost and limit the options for disposal. The case for designing a bactericide program to match, and not exceed, the required amount of bacterial control is clear, but rarely is the bacterial load determined during and after the job to verify this balance.
Herein, we report a case study undertaken to evaluate the bacterial load of field mix water and flowback water during and after a large hydraulic fracturing job in the Marcellus Shale. A novel oxidative biocide product was used during the fracturing job that has both an effective fast kill and a low toxicity profile (e.g. HMIS rating of 1,0,0). Because of its rapid biodegradability, there was concern that the effective kill of this biocide would not persist beyond a few days. Industry standard techniques (NACE Std. TMO194-94) for quantifying bacteria were applied to water samples taken during the job and over several weeks of production. The biocide was also evaluated for compatibility with common fracturing additives and for its corrosivity to surface equipment and tubular goods.
This study determines that the new biocide does not persist in flowback water beyond a few days. However, analysis of flowback water samples reveals that the bacteria count stays low (less than 10 cells/mL) for up to 81 days after application of this biocide in a slickwater fluid. Additionally, genetic fingerprinting using Denaturing Gradient Gel Electrophoresis Analysis (DGGE) was applied to the bacteria in the initial field mix water to allow comparison to any bacteria detected in the flowback samples. This paper will describe the details of this case study.
Since the completion of this case study, we have successfully deployed this technology on treatments in the Barnett, Haynesville, Marcellus, and Granite Wash shale regions. This paper reveals details of a field test and of the efficacy of this biocide as tested in flowback waters from the Piceance and Marcellus Shale basin. The results of the bacteria enumerated from each job site sample are presented. Finally, dosage requirements for biocidal efficacy were optimized for slickwater hydraulic fracturing applications are described.
Gas Well Deliquification Using Microwave Heating
Authors: Mohamed kamal , Ghodke Nikhil , Patwardhan S. D. , Al-Dogail Fuad 
Published: September 2011

Abstract
One of the challenging problems of gas production is the liquid loading of a gas well. It is the inability of the produced gas to remove the produced liquids from the well bore. This phenomenon has a significantly negative impact on gas well production rate and reservoir pressure due to build up of liquids in the well bore. The accumulated liquid may be in the form of formation water, condensed water or hydrocarbons condensate which acts as a hindrance to the formation gas getting produced. The ultimate recovery of gas is dependent on the economic removal of accumulated liquids, to allow the gas to get produced.
This paper discusses a new idea of using dielectric heating using microwaves to heat and vaporize the water and hydrocarbons in the wellbore, if present. As a result of this heating, the fluid density decreases and the gas and vapours flow naturally to the surface. The frequency of microwaves in general is 2450 MHz; depending on the need, the frequency can be varied. Experiments were carried out on the use of this technology and the results are encouraging. This paper discusses this new technique, results obtained from conducted experiments, and provides advantages to the current methods.
The Effect of Surfactants on the Kinetics of Hydrate Formation
Authors: Ramaswamy Divya , Sharma Mukul M. 
Published: September 2011

Abstract
Dissociation of gas hydrates has been the primary concern of the oil and gas industry for flow assurance, primarily in an offshore environment. There is also a growing interest in the rapid formation of gas hydrates for gas storage, transport of natural gas and carbon sequestration.
In this paper, we experimentally measure the kinetics of formation of methane hydrates and the effect of various anionic and cationic surfactants such as sodium dodecyl sulfate (SDS), cetyl trimethyl ammonium bromide (CTAB) and an alpha olefin sulfonate (AOS) on the association rate constants. The importance and necessity of micelle formation in these surfactants has been studied. The effect of foam generation on the rate of formation of these hydrates has also been measured.
SDS was found to significantly increase the rate and decrease the induction time for hydrate formation. On the other hand, CTAB and AOS have an inhibiting effect. We observed a decrease in the induction time by a factor of ten when a low concentration of SDS was used instead of only de-ionized water and methane. There was an added decrease in the induction time when a foamed mixture of water and SDS was used. The contribution of some types of micelles towards promoting hydrate formation was demonstrated with a series of experiments using SDS and other surfactants. The micelles formed by these surfactants appear to serve as nucleation sites for the association of hydrates.
New experimental data is presented to show that the use of some surfactants and the use of foam can significantly increase the rate of hydrate formation and decrease the induction time. Other surfactants are shown to act as inhibitors. An experimental setup, protocol and analysis method is presented that allows us to distinguish between surfactants that act as promoters and inhibitors for hydrate formation.
Live Fiber-Optic Telemetry Downhole Measurements on Coiled-Tubing-Enabled High-Efficiency Sand Cleanout in a Subhydrostatic Well for the First Time in the Gulf of Mexico
Authors: Rudnik A. , Foinquinos C. , James K. E. 
Published: September 2011

Abstract
Gulf of Mexico (GoM) reservoirs consist mainly of unconsolidated sandstones. Elevated production rates and high near-wellbore fluid velocities increase the possibility of dragging the unconsolidated sand grains into the wellbore and surface production equipment. Formation sand invasion into wellbore is a common problem in the GoM, especially in wells not completed with sand control features or wells where initial sand control failed. Wellbore sand cleanouts, therefore, represent the majority of coiled tubing (CT) interventions in the GoM. As the reservoirs mature, the number of through tubing well interventions (TTWI) in sub-hydrostatic wells is constantly growing. These types of wells cannot sustain a full column of fluid which presents a significant challenge to maintain circulation and sufficient annular fluid velocity required to transport the solids to surface. Nitrified and foamed cleanouts can provide at-balance or slightly over-balanced downhole conditions necessary to minimize the fluid losses into formation. Nitrified cleanouts are normally considered as more cost effective solution which is quite important since most of the sub-hydrostatic wells are very marginal producers. However, planning and execution of nitrified jobs require accurate well information which is not always accurate or available. This drives the operators to make the most common decision; to utilize the more expensive and extensive cleanout technique - the foamed cleanout - in order to ensure job objectives with reduced risks.
Real-time downhole measurements provided by a fiber-optic enabled telemetry CT helps overcome the typical challenges and operational risks associated with sub-hydrostatic well cleanouts; it also helps reduce the overall operational costs by making the job more efficient in terms of time, equipment and product usage. This paper will present a case study of the first optimized CT sand cleanout in the Gulf of Mexico.
Performance Evaluation of a Plunger Assisted Intermittent Gas Lift System
Authors: Bello O. , Falcone G. , Xu J. , Scott S. 
Published: September 2011

ABSTRACT
Several techniques have been investigated to date to alleviate the detrimental effect of liquid loading in gas wells. However, relatively little is known about the theoretical and operational aspects of plunger-assisted intermittent gas lift for gas well deliquification. This study presents an analytical approach for modeling the performance plunger-assisted intermittent gas lift system using conservation equations (continuity and momentum), thermodynamic principles and material balance.
Numerical examples are presented to illustrate the performance of the model using field data. A sensitivity study is then performed to assess the influence of different parameters on the performance of the plunger-assisted intermittent gas lift system.
Novel Drag-Reducing Agents for Fracturing Treatments Based on Polyacrylamide Containing Weak Labile Links in the Polymer Backbone
Authors: Kot E. , Bismarck A. , Saini R. K. , Norman L. R. 
Published: September 2011

Abstract
Water-soluble polymers have found extensive use in the oil and gas industry. For instance, high molecular-weight polymers are very efficient drag/friction-reducing agents and viscosifiers. Unfortunately, the adsorption of the polymer on the reservoir formation reduces the effectiveness of the recovery of oil and gas from tight low-permeability formations, such as shale. The availability of water-soluble polymers containing weak links in the backbone of the polymer that can be degraded upon experiencing a certain trigger, such as temperature, pH, or reducing agent, would be very advantageous. Because of the ability of weak links to degrade under certain conditions, such polymers can be used for their intended application and afterwards be degraded in a controlled and predetermined way. The resulting lower molecular-weight fractions of that polymer lead to reduced viscosity, quick partitioning in the water phase, and they are also less likely to adsorb onto formation surfaces. Additionally, no oxidizers need to be pumped to break or clean the deposited polymer, thus, saving time and money.
It has been proved that using a bifunctional reducing agent containing degradable groups and oxidizing metal ion as a redox couple is a facile method to initiate the free-radical polymerisation and build degradable groups into the backbone of the vinyl polymers. Temperature-degradable but hydrolytically stable azo groups showed the most desirable results. The presence of azo groups in the backbone of the synthesized polyacrylamide (PAM) was confirmed by rf-NMR spectra and differential scanning calorimetry (DSC). The degradation behavior of the PAM with temperature-sensitive azo groups was characterised using gel permeation chromatography (GPC) system and proved the multiple labile links were built into the polymer backbone. It was also found that PAM with azo links in the polymer backbone is as good a drag-reducing agent as pure PAM. However, PAM with azo links in the backbone loses its drag-reduction properties once subjected to elevated temperature, which for some applications is viewed as an advantage.
Surfactant Modeling for Insight into Load-Recovery Enhancement for Fracturing Treatments
Authors: Gdanski Rick , Funkhouser Gary P. 
Published: September 2011

Abstract
Load recovery from fracturing treatments in tight-gas sands is often considered to be an important indicator of success. Poor load recovery is often associated with poor performance, and used to invoke water blocks as a damage mechanism. Surfactants are designed and used to enhance load recovery, presumably by capillary pressure effects. A fit-for-purpose fracture cleanup and chemistry simulator (FCCS) was improved to study the impact of surfactant adsorption, surface-wettability changes, and surface-tension reduction on load recovery from hypothetical fracturing treatments.
The simulator was improved by adding surfactant adsorption/desorption kinetics, wettability functions that were dependant on the amount of adsorption, and adsorption capacities. Simulations were conducted as a function of fracture conductivity, matrix relative permeability (rel-perm) quality, and various surfactant properties. It was found that surfactants have the greatest impact when matrix rel-perm functions are of moderately good quality or better. Surface-tension reduction alone tended to simply enhance imbibition, while changing wettability to near non-wet substantially enhanced load recovery. Fracture conductivity had a substantial role because it determined whether imbibition or drawdown won the battle over water movement. The methodology of the surfactant modeling is presented, along with the results from numerous simulations.
This work demonstrates that surfactants can enhance load recovery under certain circumstances, with wettability changes being most important. However, matrix rel-perms must be of sufficient quality that capillary effects are able to overcome viscous effects.
Ultra-HTHP Scale Control for Deepwater Oil and Gas Production
Authors: Fan Chunfang , Shi Wei , Zhang Ping , Lu Haiping , Zhang Nan , Work Sarah , Al-Saiari Hamad A. , Kan Amy T. , Tomson Mason B. 
Published: September 2011

Abstract
Scale control in deepwater oil and gas production is often challenging due to not only the geological and mechanical limitation associated with deepwater wells, but also the high temperature (&gt;150°C) and high pressure (&gt;10,000 psi) environment, which may be associated with brine containing high total dissolved solids (TDSs &gt; 300,000 mg/L or greater). These extreme conditions make scale prediction, control and testing difficult because of the requirements for special alloy, pumps and control equipments that are not readily available. Therefore, very few reliable ultra-HTHP data are available. To overcome such challenges, an efficient flow-loop method has been established to study both the equilibrium and kinetics of scale formation and inhibition at ultra-HTHP conditions. This paper will discuss (1) an efficient flow-loop method to study the solubility of scale minerals at ultra-HTHP conditions; (2) solubility of barite at a temperature up to 200°C and pressure up to 20,000 psi; and (3) scale control and inhibitor selection for deepwater oil and gas production at ultra-HTHP conditions. Specifically, the performance and thermal stability of some common scale inhibitors at the high temperature conditions were studied in terms of barite inhibition. The results to-date indicated that (1) the solubility of barite at up to 200°C and 24,000 psi can be precisely measured by this newly developed flow-loop apparatus; (2) the rate of mineral scale formation at HTHP may be considerably faster than previously projected from low temperature studies and hence, difficult to inhibit; (3) different scale inhibitors have shown considerably different thermal stability. The results and findings from these studies validate a new HTHP apparatus for scale and inhibitor testings and information for better scale control at HTHP condition.
Souring Treatment with Nitrate in Fields from which Oil is Produced by Produced Water Reinjection
Authors: Voordouw G. , Agrawal A. , Park H. S. , Gieg L. M. , Jack T. R. , Cavallaro A. , Granli T. , Miner K. 
Published: September 2011

Abstract
Nitrate can control souring in fields with high bottom hole temperature (BHT) and where sulfide is produced in the near-injection-wellbore-region (NIWR). The objective of the treatment is to lower the sulfide concentration in produced water and oil, reducing corrosion risk in producing wells and above-ground infrastructure. Achieving this objective can be problematic for fields with low BHT or for fields in which the reservoir contributes sulfate to the produced water, as is demonstrated by analysing three PWRI case studies. Nitrate was found to effectively oxidize sulfide in produced waters, even when excess oil organics were present. An alternative strategy that should be considered is, therefore, to inject nitrate in the produced waters in a dose corresponding to the sulfide concentration.
Critical Evaluation of High Brine Tolerant Additives Used in Shale Slick Water Fracs
Authors: Paktinat Javad , O’Neil Bill , Aften Carl , Hurd Michael 
Published: September 2011

ABSTRACT
The primary purpose of stimulating shale reservoirs is to allow as much contact with the reservoir rock as possible, extend drainage radius, and maximize Stimulated Reservoir Volume. Slick water fracturing has increased significantly with the advent of horizontal shale stimulation. Technological advances, including multi-stage fracturing of horizontal wells, have brought about an increase in frac volume of up to several million gallons of slick water per well. Recent restrictions by local and state regulatory entities have put limits on fresh water usage.
Concerns over the disposal and environmental impact of flowback water have created challenges for industry. To remedy some of these concerns and reduce operational cost, some operators are adopting different methods of managing large volumes of produced water by chemical and mechanical methods, in order to remove solids and iron from flowback water so it can be reused in fracturing. However, most treatments currently used do not remove dissolved salts from treated waters, therefore recycled water not only exhibits overall high salinity, but also increased multivalent ionic content.
When these conditions exist, the current commercial additives perform under par, thus necessitating the development of high brine tolerant chemicals. Searches for and development of these types of chemicals began early in 2009, and were done in part to meet operational demands, while reducing chemical costs and environmental impact. These goals can be achieved by using less friction reducer per job. This paper describes friction reducer performance and other chemical selections that tolerate high salinity flowback waters.
This study critically examines the performance of a newly-developed slick water system in high salt concentration brines containing mono and multivalent ions. Average water analyses of different shale reservoirs were used to determine the performance characteristics of the additives used in slick water fracturing. A friction flow loop was used as the main measurement tool in evaluating the rheological properties of the polymers, as well as the effect of other additives used in slick water fracturing.
This new slick water system incorporates a high molecular weight polyacrylamide in a water internal emulsion as a friction reducer, which shows significant improvement over commercially available friction reducers of similar charge and molecular weight currently used in the industry. A ten gallon capacity friction loop was utilized to pump the fluid through one-quarter inch pipe at a Newtonian Reynolds number of 52,000. Results of this study, along with compatibility data, were used to select a polymer system that exhibits high resistance to brine. Experimental and field data illustrated in this study show significant performance improvement of slick water treatments where high brine water is used in shale fracturing.