bluuebunny/crossref_metadata_2025_split huggingface dataset:
Solids-Free Fluid Loss Pill for High Temperature Reservoirs
Authors: Gamage Pubudu , Deville Jay P. , Sherman John 
Published: June 2014

Abstract
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 utilized 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 cross-linkers in monovalent high-density brine. Under ambient pressure and temperature conditions, the pill flows as a viscous liquid and remains fluid for over six months. Upon exposure to elevated temperatures (200°F to 375°F), the pill cross-links 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 three weeks under HTHP 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 core flooding experiments using Berea core plugs. Average fluid loss over 3 days at 320 °F was about 50 mL. 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.
Long-Term Dynamic Flow Testing of Propants
Authors: Kunnath Aven Nevil , Weaver Jim , Tang Tingji 
Published: June 2014

Abstract
The purpose of using proppants in a fracture is to create a hydraulically conductive pathway for reservoir fluids that is open to flow and stays open. Most propped fractures, however, experience a loss of flow capacity with time. Several mechanisms have been identified that contribute to this loss, such as mechanical failure of proppant grains, proppant embedment, fluid residue damage, formation spalling, etc. Recently, fracture diagenesis has been proposed as an additional mechanism that can significantly contribute to the slow loss of fracture conductivity.
Previous attempts to quantify the degree of diagenetic activity have been made under conditions of stress and temperature, but without dynamic fluid flow. This paper presents an automated experimental setup that enables long-term (six months or more), dynamic flow testing using multiple test cells to allow evaluation of multiple proppants simultaneously at reservoir temperature conditions, but without stress applied.
This apparatus was used to determine the rate of diagenetic activity on sand and ceramic proppants with slow, continuously flowing simulated formation water. Permeability loss data for four proppants and six coated proppants subjected to 350°F flowing simulated formation water for six months are presented. Scanning electron microscope (SEM), energy-dispersive X-ray (EDX) spectroscopy, and grain strength data are presented to describe the onset of diagenesis. Dynamic permeability was monitored throughout the test period along with produced fluid ionic content as determined by inductively coupled plasma (ICP). Mass changes of each test proppant were measured.
Results presented in this paper should be helpful to stimulation engineers responsible for selecting proppants for sustained fracture conductivity. It provides detailed description of an automated laboratory method in which proppants can be evaluated for long periods of time with little human interaction.
Impact of Polymer Mechanical Degradation on Shear and Extensional Viscosities: Towards Better Injectivity Forecasts in Polymer Flooding Operations
Authors: Dupas A.. , Hénaut I.. , Rousseau D.. , Poulain P.. , Tabary R.. , Argillier J. -F. , Aubry T.. 
Published: June 2014

Abstract
Field data from polymer flooding operations sometimes indicate a better-than-expected polymer injectivity below fracturing pressure. Current interpretations for this unexpected phenomenon are based either on geomechanical considerations (for unconsolidated sand formations) or on polymer mechanical degradation, potentially occurring in the injection facilities and the near wellbore area. In this paper, a new approach of polymer injectivity is suggested. It is based on the study of polymer mechanical degradation with respect to both shear and extensional viscosities.
In the first part of this work, we have investigated the onset of mechanical degradation by submitting semi-dilute solutions of high molecular weight partially hydrolyzed polyacrylamide (HPAM) to extensional laminar flow created by an API capillary system. We have then measured both shear and extensional viscosity of the native and the degraded HPAM solutions. We consider the onset of mechanical degradation to be reached when shear viscosity loss is equal to 10%. At low degradation rate, shear viscosity is unaffected while extensional viscosity decreases up to 30%, whereas, at higher degradation rates, shear viscosity drops by 10% (onset) while extensional viscosity is reduced up to 60%. This means that degraded HPAM with weakly affected shear viscosity can develop much less resistance to extensional flow.
In the second part, we have explored the influence of mechanical degradation on injectivity by determining resistance factors of native and degraded HPAM solutions. Solutions have been injected in reproducible unconsolidated sand packs. At low velocities, resistance factors were similar for both kinds of solutions, as expected from their comparable shear viscosities. However, at high velocities, namely where flow in porous media implies high extensional deformations in the vicinities of the pore throats, apparent rheo-thickening was much less marked for solutions degraded at high extensional rate.
These results allow understanding why polymers which do not seem to be mechanically degraded according to their shear viscosity can show a very good injectivity, thanks to the reduction of extensional resistance in porous media. They could also lead to establish guidelines for designing new polymer pre-treatment methods aimed at improving injectivity while retaining the mobility control ability of polymers.
Sorption Study of ?-ALO(OH) Nanoparticle-Crosslinked Polymeric Scale Inhibitors and Their Improved Squeeze Performance in Porous Media
Authors: Yan C.. , Kan A.T.. T. , Wang W.. , Yan F.. , Wang L.. , Tomson M.B.. B. 
Published: June 2014

Summary
Polymeric scale inhibitors are widely used 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 (NP)-crosslinked polymeric scale inhibitors were developed for scale control. Nearly monodispersed boehmite [γ-AlO(OH)] NPs with average size of 2.8 nm were synthesized and used to crosslink sulfonated polycarboxylic acid (SPCA). Crosslinked AlO(OH)-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. Study of sorption of SPCA onto AlO(OH) NPs under different pHs with and without assistance of Ca2+ was discussed. In addition, study of sorption of various types of scale inhibitors [SPCA; phosphino-polycarboxylic acid (PPCA); and diethylenetriaminepentatakis(methylene phosphonic acid) (DTPMP)] onto AlO(OH) NPs was performed. Squeeze simulation of neat 3% SPCA, AlO(OH) (3%)-SPCA (3%) NPs, and AlO(OH) (3%)-SPCA (3%)-Ca NPs was investigated. The results showed that the addition of Ca2+ ions improves the squeeze performance of SPCA, and the normalized squeeze life (NSL) of such material (8,952 bbl/kg) was improved by a factor greater than 60 compared with that of SPCA alone (152 bbl/kg).
Rock/Fluid Chemistry Impacts on Shale Fracture Behavior
Authors: Aderibigbe Aderonke A. , Lane Robert H. 
Published: June 2014

Abstract
At realistic surfactant concentrations used in fracturing fluid additives, the differences in the average strengths of shale exposed to solutions of these additives are not sufficient to establish a direct correlation between the chemical effect of the surfactants and the mechanical strength of the formation. Prior studies of formations with high quartz content suggest that the adsorption of surfactant on the surface alters formation strength. In this study, using Mancos shale samples, the rock mineralogy, total organic carbon and cation exchange capacity of the Mancos shale samples were determined in order to characterize the shale. Adsorption tests to study the interaction of the shale and aqueous fluid mixture were also carried out using surface tension measurements. The uniaxial compressive strengths and indirect tensile strengths of about 100 rock samples exposed to different fluid environments were measured using unconfined compression and Brazilian tests respectively. Microseismic events, possibly due to microfracture generation or growth, are known to continue for some time as stresses relax after shutdown of hydraulic fracture pumps. Hence, the study of the role of surface chemical effects in compression and tensile fracturing is important in determining whether rock/fluid chemistry can be exploited to improve the growth of conductive microfractures.
Development of a Dual Functional Kinetic Hydrate Inhibitor for a Novel North Sea Wet Gas Application
Authors: Webber Peter , Morales Noah , Conrad Peter , McNamee Kevin , Jones Regan , Vries Gert de , Garming Linda 
Published: June 2014

Abstract
With fields getting more mature and discoveries getting smaller, operators in the North Sea are pushed to reduce development and operating costs. In order to address this challenge, they develop small fields as wet gas subsea satellites and investigate centralizing existing gas processing facilities. Both require wet gas to be transported over increasing distances. This presents an extended challenge for traditional thermodynamic hydrate inhibitor (THI) solutions as increasing subcooling equates to larger volumes being required. The application of low dosage hydrate inhibitors (LDHI) helps to unlock these new smaller fields reducing project expenditure for platform storage, transport, and pumping of hydrate inhibitor while maintain subcooling protection.
A further refinement is to require the application of a kinetic hydrate inhibitor (KHI) with dual functionality. The KHI is to serve as a traditional KHI during steady-state operations while performing as a THI during extended shut-ins and cold-well restarts. This challenge required the development of a step-change polymer technology as a fit for purpose solution.
The minimum performance requirements for the KHI incorporated hydrate forming conditions of 8 °C subcooling and 200 hours of hold time in blind rocking cells.&nbsp; Besides the high level of subcooling and extended hold time, several secondary chemical properties were essential to success. The expansion of polymer solubility (lower critical solution temperature) in 10-15% NaCl brines at temperatures up to 90 ºC for high temperature injection, polymer package formulation in a traditional thermodynamic inhibitor carrier for chemical deliverability, and extensive compatibility testing with a corrosion inhibitor were identified as key factors and rigorously examined to ensure a suitable inhibitor for the vast application.
This paper describes the qualification process, related lessons learned, and successful first application of this new kinetic hydrate inhibitor offering.
Estimating Scale Deposition through Reservoir History Matching in the Janice Field
Authors: Vazquez Oscar , Young Callum , Demyanov Vasily , Arnold Dan , Fisher Andrew , MacMillan Alasdair , Christie Mike 
Published: June 2014

Abstract
Inorganic scale precipitation and deposition in production wells can be a significant impediment to effective reservoir management. In extreme cases scale can cause the well to be abandoned as a result of reservoir formation damage in the near wellbore area and the narrowing of the production tubing annulus thus preventing fluid flow. The prediction of the time and location of scale formation is therefore essential for scale management. This study is focused on sulphate scales, which form when sulphate rich seawater mixes with formation brines, rich in barium, strontium and calcium, and which are amongst the most difficult types of scale to prevent and remove.
Formation brines in reservoirs with a tendency for sulphate scale deposition can have a very different makeup when compared to seawater, which may be injected for pressure support. Having such different chemistries allows seawater and formation brine to be tracked. In this study, two different types of water are considered, formation brine and injected seawater.
The objective of this work is to predict uncertainty in sulphate scale deposition from multiple history matched reservoir models, by tracking injected seawater in the Janice Field. There are many examples in the literature where conventional reservoir history matching, namely gas rate, oil rate and bottom hole pressure, are used to generate an ensemble of good history matched models, which will determine the uncertainty of a hydrocarbon reservoir production forecast. In this study, the same approach will be adopted, but including produced water chemistry, in particular seawater breakthrough. This approach provides a methodology to predict the uncertainty of the formation brine and the injected seawater mixing zone within the reservoir formation. The methodology provides a Bayesian confidence interval (P10-P50-P90) in time and space for the injected seawater, identifying which wells will be at risk based on seawater breakthrough and in which zones of the reservoir mixing is more likely to occur.
Effective Propagation of HPAM Solutions Through the Tambaredjo Reservoir During a Polymer Flood
Authors: Manichand R. N. , Moe Soe Let K. P. , Gil L. , Quillien B. , Seright R. S. 
Published: June 2014

Abstract
Two new methods were developed for anaerobically sampling polymer solutions from production wells in the Sarah Maria polymer flood pilot project in Suriname. Whereas previous methods indicated severe polymer degradation, the improved methods revealed that the polymer propagated intact over 300 ft through the Tambaredjo formation. This finding substantially reduces concerns about HPAM stability and propagation through low- and moderate-temperature reservoirs. Analysis of produced salinity, polymer concentration, and viscosity indicated that the polymer banks retained low salinity and therefore high viscosity for much of the way through the Sarah Maria polymer flood pilot pattern. A strong shear- thickening rheology was observed for 1000-ppm and 1350-ppm HPAM solutions in porous media, even though the salinity was only 500 ppm TDS. Examination of injectivities revealed that these solutions were injected above the formation parting pressure in the Sarah Maria polymer injection wells. Analysis suggested that the fractures extended only a short distance (~20 ft) from the injection wells and did not jeopardize sweep efficiency. In contrast, the short fractures greatly improved polymer injectivity and reduced concern about polymer mechanical degradation.
Factors Affecting the Stability of Scale Inhibitors Used for Capillary Injection in High Temperature Wells
Authors: Griffin J. Rick , Johnstone James R. , Cotter Terry E. , O'Brien Ashleigh E. 
Published: June 2014

Abstract
In recent years, the percentage of oil production from more challenging environments has increased. In addition to the numerous engineering and logistical difficulties of working at increased depth, temperature and pressure these production zones provide a harsh environment deleterious to the performance of some critical oilfield chemicals. Scale inhibitors are one class of oil field chemicals which are deployed through squeeze treatments into the formation and/or continuous downhole injection for protection of production tubulars. As well depths continue to increase, the exposure time of the injected chemicals also increases. With temperatures in the range of 180-200 °C and pressures exceeding 10,000 psi, the effect of elevated temperature and pressure on scale inhibitor performance is a critical parameter to evaluate using chemical analytical techniques and product performance methods.
Another trend leading to increased thermal exposure is the use of thermal enhanced recovery techniques. Scale inhibitors are exposed to high temperatures in operations such as steam flooding and steam assisted gravity drainage (SAGD).
In this study, a range of chemicals have been evaluated for their short and medium-term thermal stability at 180 and 200 °C. The primary application of this data is for downhole injection and squeeze treatments prior to adsorption. Inhibitor chemical types include sulfonated polycarboxylic acid (SPCA), fluorescent tagged sulfonated polycarboxylic acid (FSPCA), phosphorous tagged sulfonated polycarboxylic acid (PSPCA), sulfonated polyacrylocarboxylic acid (SPAC), polyacrylic acid (PAA), polyvinyl sulfonate (PVS), polyamino polyether methylene phosphonate (PAPEMP), bis(hexamethylene)triamine pentakis(methylene phosphonic acid) (BHTPMP) and diethylenetriamine pentakis(methylene phosphonic acid) (DTPMP). In most cases the sodium or potassium salts of the inhibitors are used.
The chemical effect of temperature on scale inhibitors is measured through molecular weight determination, thermogravimetric analysis (TGA), pH change, and Fourier Transform Infrared (FTIR) analysis. The performance of these inhibitors is measured under static and dynamic conditions for inhibition of barium sulfate scale. These results help to further the knowledge of inhibitor degradation due to thermal effects and indicate the direction for further product development of thermally stable scale inhibitors.
Laboratory Evaluation of H2S Bioscavenging in Produced Water at 60°C
Authors: Harris J. B. , Stepp A. , Pierce T. , Webb R. , Jenneman G. E. , Burger E. D 
Published: June 2014

Abstract
Nitrate can control biogenic souring by lowering sulfate reducing bacteria (SRB) metabolic activity and shifting the microbial community such that nitrate-reducing bacteria (NRB) out-compete SRB for nutrients. Nitrate was applied in a laboratory study using a 20-cc packed bed upflow reactor to determine kinetic rate of H2S removal. The objectives of the testing were to (1) enrich for nitrate-reducing, sulfide-oxidizing microorganisms derived from produced water and (2) determine the kinetic rate of H2S removal at 60˚C in a synthetic medium with an H2S:nitrate molar ratio of 2, and (3) describe the microbial community involved in nitrate-mediated souring control in this system. Sulfide was measured at the face and at the discharge of the column to determine the sulfide oxidation rate. Residence time in the reactor was varied by changing flow rate but a removal rate of nearly 50% H2S was achieved across the column in one hour residence time. This paper provides a description of the microbial community cultivated at high temperature using 16S rRNA to profile the population dynamics resulting from nitrate treatment. Phospholipid fatty acid analysis was also used for taxonomic evaluation and quantifying physiological changes in the biomass due to nitrate treatment.
A Review of Current Techniques in Gamma-Ray And Neutron Log Interpretation
Authors: Stick John C. , Hartline Ralph 
Published: June 2014

Introduction
The radioactivity log may present any of several combinations of radioactivity curves depending upon the purpose for which the log is run. The log normally consists of a gamma-ray curve and one or more neutron curves which are selected to provide the specific information desired. Radioactivity logs can provide information useful in exploration for and the development of petroleum reservoirs. They are valuable also in the maintenance of wells by providing information useful to guide completion, repair, recompletion and secondary-recovery operations.

The Gamma-Ray Curve Basis for Geological Significance
The development of the radioactivity log began with the recording of the natural gamma-ray curve. The amplitude of this curve is a measure of the gamma-ray intensity in the borehole. Variations in the amplitude of this curve in a general way follow the concentration of the radio-elements in the formation.
Experience has shown that the great majority of the radio-elements of the sedimentary column are carried by the shales. The gamma-ray curve is thus able to identify the sandstones and the carbonate rocks in which petroleum reservoirs can occur, principally by their low content of shales which carry the radio-elements.
The development of a clean sandstone formation requires, during its deposition, erosional conditions which wash the sand grains free of the fine clay-mineral particles and carry them away to be deposited in another section of the sedimentary basin. This can happen on a grand scale only if erosional and sedimentation conditions are relatively stable over a long period of time. More commonly, the sorting action of the erosional forces is inadequate to fully separate the clay minerals from the sand so that a great majority of sandstones contain clay-mineral fractions.
A New Pressure Testing for Low-Mobility Unconventional Formations: A Synthetic Case Study Based on Field Data
Authors: Hadibeik Hamid , Proett Mark , Chen Dingding , Eyuboglu Sami , Torres-Verdin Carlos , Sepehrnoori Kamy 
Published: June 2014

Abstract
Testing in tight formations and unconventional reservoirs poses significant challenges when determining reservoir pressure. The primary difficulty in testing a low mobility formation is that a conventional pressure transient test cannot be applied because the buildup time required for pressure stability after a typical drawdown is excessively long. To reduce testing time, a new automated pulse test method has been developed.
The new pulse test method consists of a drawdown or injection followed by a short stabilization period. Then depending on the buildup response, a new drawdown or injection is performed followed by a short buildup. This sequence is repeated until the desired buildup stabilization is achieved and then a final extended shut-in period is used for analysis of formation properties such as pressure and mobility. The pressure stabilization time can be further reduced by implementing an adaptive pressure feedback in the system.
This new method uses sequential pressure responses and automated pressure pulses. The analysis of the final pressure yields a measurement in 0.5% range of the initial formation pressure while decreasing the wait time by a factor of 10 for a packer-type formation tester. Furthermore, the pressure measurements are analyzed to obtain reservoir permeability and storage.
The new method was tested on synthetic reservoir models and a field study. These demonstrated that the method permits a rapid appraisal of pressure measurement in comparison with conventional testing. Moreover, the implemented feedback system mitigates the supercharge effect.