bluuebunny/crossref_metadata_2025_split huggingface dataset:
Calcium Naphthenate Solid Deposit Identification and Control in Offshore Nigerian Fields
Authors: Oduola Lukman , Igwebueze Clement , Smith Oluwaseun , Vijn P. , Shepherd Andrew G. 
Published: June 2014

Abstract
Two operated fields in offshore West Africa began experiencing aggressive solid deposition challenges soon after the onset of water breakthrough for Field A and Field B. This led to significant process control and flow assurance issues in the crude processing plants. Problems experienced included: plugging of separator bridles, hydrocyclone liners and level control valves, solid loading in overboard water, poor oil-water interface and loss of retention time in separators and plugging of reject lines of the produced water treating vessels.
An extensive solid deposit identification campaign was undertaken in order to establish the composition of the samples. Calcium naphthenate (CaN) scale was identified as the major component in the solids, the first major occurrence experienced in the Gulf of Guinea for the operators of Fields A and B. A competitive screening of CaN inhibitors resulted in the pre- selection of a low dose non-acidic formulation. The CaN inhibitor formulation selected in the laboratory was then trialed in the two offshore fields, according to a well-defined set of key performance indicators (KPIs).
Results from the field trials indicated significant reduction in the solid deposition rate. The flushing of separator sight glasses reduced from three times per shift to once in four days. Hydrocyclone liners and induced gas flotation units opened for inspection following five weeks of treatment showed no significant CaN scale present. Online oil and water filtration exercise showed downward trend in solid deposition across the FPSOs in the systems of both Field A and Field B. Produced water quality was not compromised. The CaN issue is now under control and subject to a surveillance campaign.
This paper showcases an operational excellence approach to solving the CaN problem in the face of increasing solid deposition challenges in offshore operations as seen in the Gulf of Guinea and currently in other parts of the world.
Scale and Scale Inhibition Challenges for an Alkaline Surfactant Polymer Flood in a Seawater Flooded Reservoir
Authors: Alwi Noraliza , Salleh Intan Khalida , Irvine-Fortescue Jamie , Graham Gordon , Dyer Sarah , Wright Rob , Simpson Caroline , Kidd Sam , Stalker Robert 
Published: June 2014

Abstract
Scale control during Alkaline Surfactant Polymer (ASP) flooding is a recognised challenge especially following ASP breakthrough at the production wells, due to continual mixing of the high pH ASP waters with reservoir brine. The effective performance of scale inhibitors (SIs) is a problem, given the high oversaturation expected due to mixing of injected alkali and formation water. Previous work (SPE 141551) described this challenge for a conventional system whereby ASP was injected into a reservoir containing low salinity / low divalent ion Formation Water (FW). This work showed that chemical performance (SI/ brine compatibility and performance) could be achieved using conventional inhibitors and that treatment of the production wells via downhole squeeze treatments was achievable. It also demonstrated that the production of high pH ASP fluids had a considerable impact on the retention and release properties of the chemicals.
This paper progresses significantly from the previous work by examining a field case study. Although the formation water is a low salinity / low divalent cation brine similar to that in the earlier example, this field represents a considerably more severe scaling challenge since it has already been flooded with Sea Water (SW). The SW contains considerably higher divalent cation concentrations (c.f. Ca2+ ~ 450mg/l vs. ~40 mg/l for the formation water) and results in a considerably more severe challenge in terms of SI/Brine compatibility and chemical performance when examining a range of conventional SI's.
The paper describes extensive modeling of the in situ conditions for this field following ASP flooding, extensive scale inhibitor performance tests across a wide range of conditions and mixtures of ASP/FW/SW together with a series of core flood tests to assess the potential for squeeze treatments in this new pilot ASP system.
For the pilot, reservoir modelling was essential to simulate the expected mixture of ASP/FW/SW which would be produced, such that chemicals could be targeted for the expected produced mixtures (Note: increased FW:SW ratio results in more achievable inhibition) allowing chemical selection for squeeze. The pilot ASP flood in this field is now planned for 2014.
Laboratory Studies for Surfactant Flood in Low-Temperature, Low-Salinity Fractured Carbonate Reservoir
Authors: Sagi Aparna Raju , Puerto Maura , Bian Yu , Miller Clarence A. , Hirasaki George J , Salehi Mehdi , Thomas Charles P. , Kwan Jonathan T 
Published: June 2014

Abstract
The objective was to identify surfactants for Enhanced Oil Recovery by brine-oil interfacial tension reduction for a carbonate reservoir at ~ 25°C and salinity of ~11,000ppm TDS; thus, Alkyl Propoxy Sulfates and their blends with sulfonates were evaluated to determine optimal salinity and solubilization parameters with dead crude. Imbibition experiments were performed in reservoir and dolomite outcrop cores to determine the oil recovery efficiency of surfactant systems, selected from their phase behavior test results, with potential to recover oil. Tridecyl alcohol 13 propoxy sulfate (TDS-13A) with an oil solubilization parameter of ~8 at reservoir salinity was found to recover greater than 75% oil in imbibitions experiments, at a concentration as low as 0.5wt%. The adsorption of surfactants on dolomite was measured at static and dynamic conditions; the adosprtion of TDS-13A was found to be ~ 0.26 – 0.34 mg/g reservoir rock. The effect of solution gas on surfactant phase behavior, up to 600-psi, was evaluated for methane, ethane, carbon-dioxide, and separator gas at 30°C. Methane had minimal effect on surfacatant optimal salinity, lowering it by ~2%/100psi solution gas, followed by carbon-dioxide which reduced it by ~11%/100psi. Ethane had a much more pronounced effect, reducing optimal salinity by ~46%/100psi solution gas.
Solids-Free Fluid-Loss Pill for High-Temperature Reservoirs
Authors: Gamage Pubudu , Deville Jay P. , Sherman John 
Published: June 2014

Summary
The leakage of reservoir fluids into a wellbore during perforation, workover, or other completion operations is a substantial concern, especially in high-temperature wells where existing fluids used to mitigate reservoir-fluid influx offer poor performance. To maintain the hydrostatic integrity of the wellbore during these operations, a thermally stable, solids-free fluid-loss pill has been developed.
The pill is composed of synthetic polymers and crosslinkers in monovalent high-density brine. Under ambient-pressure and -temperature conditions, the pill flows as a viscous liquid and remains fluid for more than 6 months. Upon exposure to elevated temperatures (200 to 375°F), the pill crosslinks to form a robust gel that can act as an appropriately weighted, low-fluid-loss pill. This pill can temporarily seal the reservoir, enabling well control during completion operations.
Gelled samples of the fluid-loss pill have maintained integrity for up to 3 weeks under high-pressure/high-temperature (HP/HT) conditions in laboratory testing, with minimal signs of collapse. The gel can be readily destroyed with an oxidative breaker providing a substantial reduction in viscosity. At the end of the completion process, the timing of gel removal is completely controlled by the timing of the breaker addition.
In addition to gel-stability tests, formation damage caused by the gel and the fluid loss of the pill were assessed by coreflooding experiments by use of Berea core plugs. Average fluid loss over 3 days at 320°F was approximately 50 cm3. Restoration of the Berea core permeability after the treatment exceeded 85% of the initial permeability, with low lift-off pressures observed. This paper presents full laboratory data on the development of the thermally stable, solids-free fluid-loss pill, including gel-stability, fluid-loss, and breaker testing.
The Influence of Turbulence or Hydrodynamic Effects on Barium Sulphate Scale Formation and Inhibitor Performance
Authors: Sutherland Louise , Johnston Clare , Taylor William 
Published: June 2014

Abstract
Inorganic scale (carbonate, sulphate and sulphides) formation can be predicted from thermodynamic models and over recent years better kinetic data has improved the prediction of such scales in field conditions. However these models have not been able to predict the observed deposition where flow disturbances occur, such as at chokes, tubing joints, gas lift valves and safety valves. This can lead to unexpected failures of critical equipment such as downhole safety valves (DHSV's), and operational issues such as failure to access the well for coiled tubing operations due to tubing restrictions.
In recent years it has been recognised that the turbulence found at these locations increases the likelihood of scale formation and experiments have been able to demonstrate that increased turbulence also impacts the minimum scale inhibitor concentration required to prevent scale.
One of the industry standard test methods used to screen inhibitors for barium sulphate inhibition is the static bottle test. In this paper the ‘static’ bottle test method is modified to investigate the effects of increasing levels of turbulence on the formation of barium sulphate scale at two different temperatures and therefore different supersaturations for a fixed brine composition. Using this modified method it has been possible to demonstrate the impact of varying turbulence on the performance of two common generic types of scale inhibitor (phosphonate and vinyl sulphonate co-polymer). Data on the mass of scale formed, scale morphology using SEM imaging and inhibitor efficiency will be linked to degree of turbulence and scale inhibitor functionality (nucleation inhibition vs. crystal growth retardation).
The findings from this study have significant impact on the methods of screening scale inhibitors for field application that should be utilised and development of suitable chemicals that perform better under higher shear conditions.
Novel Associative Acrylamide-based Polymers for Proppant Transport in Hydraulic Fracturing Fluids
Authors: Gaillard N. , Thomas A. , Favero C. 
Published: June 2014

Abstract
The properties of novel polymers for proppant transport in hydraulic fracturing operations are discussed. Acrylamide based associative polymers have been synthesized using various industrial production processes. Anionic polymers investigated are acrylamide (AMD) based co- and ter-polymers functionalized with monomers such as sodium acrylate (AA), sodium acrylamido-tertiary-butyl sulfonate (ATBS) and a home-made surfactant monomer. The rheological properties of the developed polymers in different brines are evaluated and compared to commercial guar gums usually used for fracturing fluids. The viscoelastic properties as well as settling time of proppant in graduated cylinder have been evaluated. The impact of oxidizing breakers and surfactants added to increase or decrease the viscosity of solutions are reported as well. The new polymers can be used in slickwater, linear gel and cross-linked hydraulic fracturing fluid. They have the ability to carry the proppant down to the target zone. With this technology, proppant can be transported and placed into the fractures with lower concentrations of product and reduce or eliminate the need for using guar gum. Fluid viscosity can be controlled (either increased or decreased) by the addition of surfactants and broken by conventional oxidizers. Laboratory data shows that new associative polymers solutions give very high viscosity at low shear rate and a strong reversible shear thinning effect. Typically, for 3000 ppm of associative polymer, settling time of proppant is 10 times longer than for the same concentration of guar gum. In gel-based fracturing jobs, transport of proppant is generally achieved using guar gum whose viscosity may be improved by adding cross-linkers such as borate or zirconium. The polymer presented in this paper could be a total or partial alternative to guar for proppant transport whose price is subjected to harvest aleas. Results show that lower polymer concentrations are required to obtain the same or even better suspending properties. Besides, traditional oxidizing breakers could be replaced by surfactant to decrease the viscosity of the fluid once the proppant has been placed in the fractures.
The Application of Nanoparticle-Stabilized CO Foam for Oil Recovery
Authors: Yu Jianjia , Mo Di , Liu Ning , Lee Robert 
Published: June 2014

Abstract
This paper presents a process for CO2 foam generation in the presence of nanosilica particles as supercritical CO2 and nanosilica dispersion flow through a sandstone core at reservoir conditions of 20°C and 1,200 psig. The generation of CO2 foam was observed in an online sapphire tube. Pressure drop across the core was measured to estimate the fluid mobility and foam resistance factor. Foam mobility and particle retention were investigated and core permeability after the CO2/nanosilica dispersion flooding was also measured to determine the particle plugging in the core. The application of the nanoparticle-stabilized CO2 foam for waterfloods residual oil recovery from sandstone cores was investigated. The results indicated that nanoparticle-stabilized CO2 foam could improve oil recovery after waterfloods in both low and high permeability cores. The total oil recovery by CO2 and nanosilica flood was 48.7% from the core with permeability of 33 md and 35.8% from the core with permeability of 270 md under the pressure of 1,200 psig.
Laboratory Development of A Novel, Non-Triazine-based Hydrogen Sulfide Scavenger and Field Implementation in the Haynesville Shale
Authors: Chaudhry F. , Mobley G. L. , Tsang Y. H. , Ramachandran S. , Jovancicevic V. , Braman S. C. , Rowton E. N. , McDonald A. P. , Davis J. A 
Published: June 2014

Abstract
Hydrogen sulfide (H2S) is found in many shale gas fields. It is important to remove the H2S to allow for safe transport of the produced gas and to reduce corrosion concerns. The H2S concentration present in the gas is typically low enough that it becomes uneconomical to utilize a regenerative facility such as an amine plant. For this reason, liquid H2S scavengers are the most common mitigation strategy, with nitrogen-based triazines being the most commonly utilized scavenging chemistry. Hydrogen sulfide scavengers can be introduced by direct injection2 into mixed production or separated wet gas pipelines. They can also be reacted with H2S in scavenger flooded contact towers. Applications utilizing towers consume less H2S scavenger; however, the use of contact towers introduces additional capital costs in the operation. Often when high pH, triazine-based H2S scavengers are used, calcium carbonate scale deposition can occur because of neutral pH brine, requiring the facility to be shut in and treated with mineral acids. The reaction product of triazine with H2S can be difficult to dispose of, which increases facility operating costs (e.g. separate disposal tanks and dedicated disposal wells for spent scavenger).
A novel, fast-acting, non-triazine based H2S scavenger has been developed. This new H2S scavenger reacts quicker and has better efficiency than other non-nitrogenous based scavengers (e.g. glyoxal). The neutral pH of the new product eliminates the concern for calcium carbonate deposition that is often experienced with triazine-based scavengers. The new scavenger has been tested for thermal stability and compatibility with other production chemicals. The product has the ability to partition in oil and water phases, making it a more versatile scavenger. Finally, the new product has a better environmental profile than other commonly used H2S scavenger chemistries.
A field trial was conducted using the new non-triazine H2S scavenger. The trial included direct injection into mixed production and separated wet gas lines. Innovative engineering solutions were devised to apply the new H2S scavenger. The combination of the novel application methodology, with the new H2S scavenger chemistry, resulted in a more cost-effective means of treating sour shale gas than is currently achieved with conventional triazine-based H2S scavengers utilizing contact tower applications.
Synthesis and Sorption Study of AlOOH Nanoparticle Cross-Linked Polymeric Scale Inhibitors and their Squeeze Performance in Porous Media
Authors: Yan Chao , Kan Amy T. , Wang Wei , Yan Fei , Wang Lu , Tomson Mason B. 
Published: June 2014

Abstract
Polymeric scale inhibitors are widely utilized in the oil and gas field because of their enhanced thermal stability and better environmental compatibility. However, the squeeze efficiency of such threshold inhibitors, not only polymeric scale inhibitors but also phosphonates, is typically poor in conventional squeeze treatment. In this research, nanoparticle cross-linked polymeric scale inhibitors were developed for scale control. Nearly monodispersed boehmite (γ-A1O(OH)) nanoparticles (NPs) with average size of 2.8 nm were synthesized and used to cross-link sulphonated polycarboxylic acid (SPCA). Cross-linked AlOOH-SPCA nanoinhibitors were produced and developed to increase the retention of SPCA in formations by converting liquid phase polymeric scale inhibitors into a viscous gel. Sorption study of SPCA onto AlOOH NPs under different pHs with and without assistance of Ca2+ was discussed. In addition, sorption study of various types of scale inhibitors (SPCA, PPCA and DTPMP) onto AlOOH NPs was also performed. Squeeze simulation of neat 3% SPCA, AlOOH(3%)-SPCA(3%) NPs and AlOOH(3%)-SPCA(3%)-Ca NPs were investigated. The results showed that the addition of Ca2+ ions improve the squeeze performance of SPCA and the normalized squeeze life of such material (8,952 bbl/Kg) was improved more than 60 times compared to that of SPCA alone (152 bbl/Kg).
Identification of Sustainable Chemistries for Microbial Control in a Deep Offshore Waterflood
Authors: Sianawati E. , McGinley H. , Yin B. , Prisco A. , Lévy R. 
Published: June 2014

Abstract
Microbial control products for offshore production facilities need to meet stringent product specifications and performance criteria, and must be compatible with infrastructure such as pump capacity and materials of construction. This paper describes the biocide selection process and recommendation for an offshore operation in West Africa.
The chosen chemistries needed to demonstrate robust microbial control under field conditions for top side and downhole protection, as well as pipeline protection. Product specifications such as good chemical stability above 60°C, high flash point, low viscosity, non-corrosive, and low foaming potential also needed to be met. Additional constraints included a defined treatment protocol, and a request that both a glutaraldehyde (GDA) -based product and a tetrakis (hydroxymethyl) phosphonium sulfate (THPS)-based product be recommended.
A wide range of GDA and THPS-based products were tested against planktonic halophilic sulfate reducing bacteria (SRB's) using high throughput testing. No differentiation between products was observed under these conditions. More sophisticated test methods that evaluate kill of sessile bacteria again, showed little differentiation in the short term, but when longer-term control of biofilm regrowth was considered, two GDA formulations performed well. One was ruled out due to its high foaming potential. The leading GDA based formulation (GDA 4) and a non-foaming THPS-based formulation which also met efficacy requirements (THPS B) were further evaluated under conditions simulating microbial corrosion in a pipeline. Both mitigated corrosion relative to an untreated control as indicated by electrochemical monitoring. Corrosivity of the products towards common materials in saltwater was also considered. For Duplex 2205 and stainless steel, no significant corrosion was observed for either neat or use-concentration product. For carbon steel, THPS B showed little variation from the saltwater control while GDA 4 gave marginal protection relative to saltwater alone. Therefore both products were found to suit the requirements of the operation.
This study shows the importance of a holistic approach to microbial control beyond standard planktonic efficacy testing. The selection process should include not only efficacy against relevant microorganisms and conditions, but also evaluation of chemical and physical properties of the product.
Application of Quantitative Structure-Property Relationship (QSPR) Method for Chemical EOR Surfactant Selection
Authors: Moreau Patrick , Oukhemanou F. , Maldonado A. , Creton B. 
Published: June 2014

Abstract
The selection of high performance surfactants for chemical EOR is a challenging and time consuming task. A surfactant formulation, typically a blend of at least two surfactants must be developed for each case study. A tool to pre-select suitable surfactants would thus be highly valuable. In this paper, we describe the development of a quantitative structure-property relationship applied to the selection of surfactants for chemical enhanced oil recovery. A correlation is drawn between surfactant structures and optimal salinities, i.e. the salinity which corresponds to a minimum in interfacial tension.
A comprehensive and coherent database has been generated using a high-throughput screening robotic platform and industrial products belonging to different families of surfactants: olefin sulfonates, alkyl ether sulfates and alkyl glyceryl ether sulfonates. This database has been built for specific reference conditions (temperature, oil, brine hardness). Industrial surfactants, most often constituted of a variety of molecules, have been carefully analyzed in order to identify predominant species. The structures of these compounds have then been drawn using molecular design tools, and molecular descriptors were generated for the whole set of amphiphiles. Finally, various statistical approaches have been used to develop multi-linear regressions correlating combinations of the most relevant molecular descriptors with the experimentally determined optimal salinity of surfactant mixtures.
Our results indicate that a strong correlation exists between the surfactant structure and its optimal salinity. A limited set of descriptors can be used to predict this critical property with predictive models. These models can then be used to select promising existing products as well as to identify candidate raw materials or products for industrial surfactants development. We also demonstrate the ability of our models to predict optimal salinity of surfactant blends typically used in chemical EOR.
Future developments will be focused on extrapolation of these models to the prediction of other application properties for chemical EOR (e.g. interfacial tension value) and to broaden the application domain to a wide range of conditions (temperature, brine composition, type of oil).