bluuebunny/crossref_metadata_2025_split huggingface dataset:
Scaling of Calcium Carbonate on Heated Surfaces - Crystallization or Particulate Fouling?
Authors: Broby Margrethe , Neteland Marte , Ma Xiaoguang , Andreassen Jens-Petter , Seiersten Marion 
Published: April 2016

Abstract
One of the main challenges with mono ethylene glycol (MEG) loops is to achieve controlled removal of produced salts and at the same time avoid uncontrolled precipitation and scaling on heat exchanger surfaces. Scaling is described in the literature as occurring both by particulate and crystallization fouling which is of particular interest in MEG regeneration processes with heat exchanger surfaces being exposed to solutions with significant quenatities of particles in the liquid bulk. In order to control the process it is essential to understand to which extent scale formation is driven by crystal growth on the surface as compared to particulate fouling of particles originally precipitated in the liquid bulk.
Surface scaling was studied in a laboratory setup where a heated stainless steel tube is inserted in a well-mixed continuously stirred tank reactor allowing for control of the steady state supersaturation and the bulk temperature. To test if particulate fouling is contributing to the scale formation premade particles of a different calcium carbonate polymorph was seeded to the system.
By running the system with pre-scaled tubes of calcite and at the same time seeding with vaterite particles, it was shown that particulate fouling is not an important growth mechanism. For aragonite scales produced on a tube heated at 90 °C, we found that vaterite particles were incorporated to a certain extent into the porous scale structure. However, the simultaneous consumption of supersaturation by the vaterite particles in solution as well as by the scale layer, atually lowered the scale thickness. This reduced scale layer growth was confirmed by heat exchanger data.
We found that particulate fouling is not an important mechanism for build-up of calcium carbonate scales. Presence of bulk particles can even be advantageous by reducing the available supersaturation for surface scaling.
Advances in Understanding Effects of Shear and Turbulence on Scale Formation, Adhesion and Growth on Surfaces
Authors: Nichols David A. , Frigo Dario M. , Graham Gordon M. 
Published: April 2016

Abstract
Inorganic scale formation in oilfield systems is greatly influenced by the fluid-flow regime, with shear rates and turbulence affecting nucleation, surface growth, morphology and adhesion. However, current scaling risk analysis relies upon thermodynamics-based predictions together with simple rules-of-thumb to address kinetics because the impact of flow regime is poorly understood. Similarly, scale inhibitor performance is typically evaluated under static or low-shear, laminar-flow conditions, which are highly unrepresentative of those in most production systems.
This paper examines scale deposition at metal surfaces and bulk-phase precipitation as a function of shear and turbulence, highlighting how rate and even scale composition can change in systems with mildly oversaturated sulphate tendencies. Conventional static and low-shear methods are compared with those using rotating cylinder and jet impingement to achieve high Reynolds numbers and shear stresses up to 400 Pa (and even 10,000 Pa via more sophisticated approaches). This builds upon earlier work (SPE 169761) and demonstrates the influence of fluid-flow dynamics on the critical supersaturation required to induce scaling, and by extension, on the nature of the deposit that may form where a system is mildly oversaturated for more than one scale. An example is where a sulphate scale at lower supersaturation precipitates under high shear conditions preferentially over another sulphate scale with higher supersaturation.
This work also highlights the significance of better matching shear and turbulence in the ranking of scale inhibitors, reporting differences in the relative performance of different generic inhibitors as a function of shear.
Finally, the paper describes the new test methods by which scaling propensity and inhibitor performance can be determined under conditions of shear and turbulence that are more representative of production conditions. A key aspect of this is that it facilitates testing of mildly supersaturated systems without having to adjust brine chemistry, leading to better understanding of the magnitude of uncontrolled scaling and of the Minimum Effective Dose of inhibitors to control it.
Impact of FeIII/FeII on Scale Inhibition
Authors: Zhang Zhang , Liu Ya , Dai Zhaoyi , Bhandari Narayan , Zhang Fangfu , Yan Fei , Ruan Gordon , Alsaiari Hamad , Lu Yi-Tsung , Deng Guannan , Kan Amy , Tomson Mason 
Published: April 2016

Abstract
Little research has been done to understand how chelating agents might reverse the effect of Fe(III)/Fe(II) on scale inhibitors in oilfield conditions. Iron ions are common cations existing in oil and gas production water. Most Fe(II) ions come from dissolution of siderite in reservoir and corrosion of steel pipes. Fe(III) in solution, can be formed by Fe(II) reduction of H2O, dissolution of magnetite or other Fe(III) containing minerals or when produced water is exposed to air. Both Fe(II) and Fe(III) can cause severe problems in production. Fe(II) can form FeS and FeCO3 scale. Fe(III) can precipitate as ferric hydroxide or with Fe(II) as magnitite particles and cause damage to formation permeability. Moreover, both Fe(II) and Fe(III) have significant detrimental effects on common scale inhibitors. One of the most popular methods for iron control is the application of chelating agents, such as EDTA, NTA or citric acid, to chelate Fe(II)/Fe(III)to prevent such detrimental effects.
In this work it is shown that Fe(II) and Fe(III) can significantly impair performance of common scale inhibitors such as DTPMP, PPCA and PVS. The inhibition time of DTPMP for barite can drop more than 90% in the presence of 1 mg/L Fe(II) or Fe(III)at 70°C. In this research, a mechanistic study has been done to deduce whether EDTA and citric acid can reverse the loss of scale inhibitor performance by Fe(II)/Fe(III). We find that Fe(III) impairs scale inhibitor performance by forming iron hydroxide particles which can adsorb scale inhibitors from solution. Both EDTA and citric acid are found to be able to eliminate the negative impact of Fe(III) on scale inhibitors, but through different mechanisms. EDTA works by direct chelation of Fe(III) in solution, before a solid phase is formed; while citric acid works by competitive adsorption with scale inhibitor onto ferric hydroxide particle surfaces. The impact of EDTA and citrate on reversing Fe(II) effect on scale inhibition is also discussed.
High Pb and Zn Concentrations in Formation Water from the Culzean Field: Real or Artefact?
Authors: McCartney R. A. , Brice S. , Chalmers A. 
Published: April 2016

Abstract
Formation water compositions are an important input to scale management planning on new fields. The quality of these data can be verified by evaluating formation water sampling and analysis conditions and also by comparing the analyses with analogue data from similar fields. But, this can be problematic when the analyses of interest are not commonly obtained. In this paper we present such an example.
The HTHP Culzean Field is located in Block 22/25a, East Central Graben, UK North Sea. Although an initial evaluation of formation water samples/analyses obtained from the Skagerrak Formation indicated that their quality was reasonably good, the formation water contained 172±9 ppm Pb and 452±24 ppm Zn. These concentrations are high when compared with the few published/unpublished analyses for North Sea formation waters; at these concentrations there is a potential Pb-Zn sulphide scale risk at Culzean.
To confirm the Pb and Zn analyses, they were compared with a wider variety of analogue data from a range of crustal fluids (including other global oilfield formation waters, and shield, geothermal, metamorphic, hydrothermal, and magmatic waters). This showed that the Culzean formation water has a Pb/Zn ratio characteristic of crustal fluids and the high concentrations appear to be the result of (a) a geological source of Pb and Zn, (b) high salinity, low pH and low total reduced sulphur content of the Culzean formation water and (c) high reservoir temperature. It was concluded that high Pb and Zn concentrations of the Culzean formation water are likely to be representative of those naturally-occurring in the reservoir and are not an artefact of drilling, sampling or analysis.
This study has shown that analogue data from a variety of crustal fluids can be used to establish the quality of oilfield formation water analyses. This is particularly useful when the constituents of interest are not commonly detected or determined in oilfield formation waters. This has helped confirm the potential sulphide scale risk at Culzean and explains the reasons for elevated Pb and Zn in formation waters from other fields in the East Central Graben of the North Sea.
Accurate Detection of Tagged Polymeric Scale Inhibitors in Oilfield Produced Water Samples
Authors: Vuori Vesa , Nuutinen Vesa , Honkanen Tapio , Griffin Rick , Johnstone James , Peltokoski Brita , Lehtonen Annika , Suominen Hanna , Toivonen Susanna 
Published: April 2016

Abstract
Accurate detection of scale inhibitor residuals from produced waters is a critical part of flow assurance. Tagged scale inhibitors have been developed to improve the detection limit. The purpose of having multiple different tags on the same inhibitor chemistry is to be able to separately detect the level of inhibitor for several subsea templates when commingled in a single flow back line to a production facility. These new tagged scale inhibitors combine the excellent scale inhibition performance of sulphonated copolymers with fluorescence technology, delivering lower detection limits of residual inhibitor concentrations.
The authors have developed a testing protocol that enables accurate detection of two tagged scale inhibitors from a produced water sample using fluorescence spectroscopy. The development of the chemistry and detection monitoring technique, and the results demonstrating the validity of the analysis method are discussed. The method has been validated and tested with real produced water samples collected from a subsea field in the North Sea. The samples were spiked with unknown concentrations of two fluorescent tagged sulphonated copolymers with concentrations between 0 and 200 ppm as product.
The tested products have specific excitation and emission wavelengths, enabling the independent detection of both products with a fluorometer without any disturbing effect. The test results clearly show that the protocol can be used for analyzing low concentrations of scale inhibitor polymers from produced waters. The final goal is to analyse residual inhibitor concentrations using a portable fluorometer delivering onsite detection, and thus enabling real-time monitoring of the scale inhibitor squeeze returns.
This fluorescence technology can be used in combination with a phosphorus tagged scale inhibitor and ICP analysis method to detect three products from the same commingled sample. The validity of the protocol has been confirmed and has generated great interest in the oil and gas industry where accurate detection will maximize safe and economic oil production.
Introducing Novel Chemistry for Scale Inhibitor Squeeze Treatments on the Heidrun Field - Challenges Faced and Lessons Learned
Authors: Williams E. , Archibald M. , Selle O. M. , Brandal Ø. , Carter J. , Singaravel V. , Henriksen O. , Gustavsen Ø. , Andresen A. M. 
Published: April 2016

Abstract
Heidrun is recognised as a challenging field for scale management due to the combination of water injection, high barium and clay content, and unconsolidated sandstone formations. A selection and qualification process for scale inhibitor squeeze in this field followed the standard laboratory testing protocols. A novel scale inhibitor chemistry was qualified and field trialled; however, introducing the new scale inhibitor chemistry to the field was more challenging than anticipated.
The technical qualification was successful but the field trial resulted in lost productivity, halting field-wide implementation. The field trial started in Well I and indicated good scale protection but gave considerable loss of productivity. This paper presents the lessons learned through an extensive laboratory investigation to identify specific factors influencing the issues observed with the field trial. Furthermore, work completed to qualify a solution for iron-rich formations is described.
It was determined that the inhibitor was leaching iron from minerals in the reservoir and forming an insoluble complex with the metal, particularly at mildly acidic pH. While elevated iron concentrations were seen in flow-back samples from other wells across the field, these did not approach the levels observed for Well I which was producing from a geological formation rich in iron-bearing minerals. The field trial was successful in less iron-rich formations and the product was implemented field-wide for such reservoir zones. The scale inhibitor was designed to offer strong chelation, a property suited to scale inhibition and reservoir retention, but this was also a significant factor in the productivity loss. This important finding dictated that Product A should be regarded as unsuitable for reservoir zones containing iron-rich minerals. Subsequently, an alternative scale inhibitor was technically qualified and has since been successfully field trialled and implemented in the iron-rich formation.
This selection exercise for Heidrun posed challenges in terms of reservoir retention and iron compatibility for field-wide implementation of new chemistry. Overcoming these issues gave valuable insights for future qualifications of the novel scale inhibitor chemistry.
A Comparison Study on Huff-n-Puff Gas Injection and Chemical Relative Permeability Modification to Mitigate Condensate Blocking in Fractured Shale Gas Condensate Reservoirs
Authors: Sheng Jie , Sheng James J. , Li Lei 
Published: April 2016

Abstract
In the literature, both huff-n-puff gas injection and chemical injection to modify relative permeabilities have been proposed to mitigate condensate blocking near the wellbore; and huff-n-puff gas injection has been proposed to improve liquid oil production in shale gas condensate reservoirs. This paper focuses on the potential of chemical relative permeability modification (RPM) to enhance hydrocarbon recovery in fractured shale gas condensate reservoirs using the simulation approach; and the potentials to improve hydrocarbon recovery by these two approaches are compared.
The relative permeability model is studied and the dependence of gas/oil relative permeability curves on capillary number and interfacial tension is discussed. Chemical treatments to mitigate condensate and water blocking have been successfully implemented in the laboratory with sandstone and carbonate. Accordingly, a brief screening of RPM chemicals is conducted and the mechanism of potential surfactant molecules that may work in shale gas condensate reservoirs are investigated. In this study, a shale gas condensate reservoir model is set up and the reservoir is assumed to be treated with a hypothetic surfactant that improves both the relative oil and gas permeability within the near-wellbore area. The simulation results are juxtaposed with those of huff-n-puff gas injection production.
It is assumed that the surfactant alters the end-point gas/oil relative permeability, residual oil saturation, gas connate saturation, etc. and is durable during the production years. In the surfactant treatment cases, an increase of oil recovery by 1%-3% is observed compared with the primary depletion. However, the optimized huff-n-puff process can achieve up to 8% more oil recovery than primary depletion. In terms of gas recovery, the surfactant treatment process increases gas recovery by 1-2%, while the optimized huff-puff gas injection leads to over 20% gas recovery reduction because of less total production time. To sum up, the huff-n-puff gas injection process achieve more liquid recovery but less gas recovery than the surfactant treatment process. Analysis of simulation data about the changes in drawdown pressure and liquid saturation are proposed. A simple economic analysis is conducted as well. It is concluded that the huff-n-puff process is preferred to the RPM process when the oil price is relatively high due to higher drawdown pressure and the oil saturation reduction near the wellbore by evaporation.
The potential of RPM application in unconventional reservoirs has not been well investigated in the previous literature. This paper is to discuss this potential and to compare the advantages and disadvantages of the surfactant RPM process with those of huff-n-puff gas injection in shale gas condensate.
An Experimental Investigation of Desorption Kinetics and Mass Transfer in Shale
Authors: Wang Yu , Dasani Devang , Tsotsis Theodore T. , Jessen Kristian 
Published: April 2016

Abstract
Methane (CH4) is the largest component of the natural gas produced from shale rocks. Although methane accounts for 87-96 mol% of the gas from these rocks, other components including hydrocarbons such as ethane (C2H6) and propane (C3H8), nitrogen (N2) and helium (He) are also found in the gas produced. Methane and the various heavier hydrocarbons are stored in an adsorbed state in the micro and mesopores of the shale rocks, and as free gas in the fracture networks. Though convective and diffusive transport accounts for the short-term behavior in gas production, desorption is thought to dominate the long-term dynamics of shale-gas generation. The key objective of this study is the investigation of adsorption/desorption and diffusive transport phenomena of methane/hydrocarbon mixtures in shale-gas rocks.
We focus our attention on the pure components of methane and ethane and their binary mixtures, since ethane is typically the second largest component in shale gas, and is thought to compete for the same adsorption sites in shale-gas rocks as methane. We study the adsorption/desorption behavior of this mixture (and its individual components) in ground shale rock samples using thermogravimetric analysis (TGA). The sorption isotherms generated are important to predict the gas storage capacity of the shale samples, while the study of adsorption/desorption dynamics/kinetics help us understand the role of desorption during the later times of gas production. A dynamic Langmuir-type sorption model is proposed, that allows us to isolate desorption kinetics from diffusive mass transfer. This, in turn, facilitates our modeling and interpretation of the experimental observations.
The experimental observations and their interpretation pave a path to improve the interpretation of production data from shale-gas wells by leveraging an improved understanding of desorption dynamics and mass transfer of natural gas mixtures in shale.
A Petrophysical Dual Porosity Model for Evaluation of Secondary Mineralization and Tortuosity in Naturally Fractured Reservoirs
Authors: Piedrahita Jaime , Aguilera Roberto 
Published: April 2016

Abstract
Quantification of secondary mineralization or cementation within natural fractures has not been considered in previous petrophysical dual porosity models. This is however of paramount importance as morphology of the fractures indicates that they can be open, partially or completely mineralized.
If cementation with secondary minerals is complete the recovery of hydrocarbons will be generally very small. If secondary mineralization is partial, production rates and recoveries could be quite significant as the secondary minerals would play the role of natural proppant agents helping to maintain the fractures open as the reservoir is depleted. If the fractures are initially open, production rates and recoveries could be large or small dependent on the orientation of the natural fractures and in-situ stresses.
These observations lead to the key objective of this paper: to develop an analytical dual porosity model for quantifying secondary mineralization (cementation) and tortuosity in natural fractures. The method further allows estimating matrix and fracture porosities, and fracture compressibility based on the amount of secondary mineralization.
Use of the new dual porosity model is explained with two core data sets drawn from tight gas formations in the United States and Canada. A comparison is made with results of current dual porosity models that do not take into account secondary mineralization within the natural fractures and tortuosity.
The conclusion is reached that the proposed dual porosity model provides a valuable new quantitative tool for petrophysical evaluation of naturally fractured reservoirs. In addition, the methodology allows estimating fracture compressibility, a usually elusive parameter needed for estimating original petroleum in place in naturally fractured reservoirs. Although the methodology is explained using data from tight sandstones it also has application in other types of reservoirs and lithologies.
Infill Drilling Opportunity in Fruitland Coal, San Juan Basin, Colorado
Authors: Parihar Prannay , Warner Russell , Micikas James , Armpriester Lianne , Anderson James , Zuluaga Elizabeth 
Published: April 2016

Abstract
The San Juan Basin, located in northwestern New Mexico and southwestern Colorado, is one of the most prolific natural gas producing regions, and one of the largest gas basin in the United States in terms of total estimated gas reserves. More coalbed methane has been produced from the San Juan Basin than the rest of the world combined. This paper analyzes the performance of original and infill wells producing from the Fruitland Coal formation and offsetting Chevron's acreage position in key areas of the North San Juan Basin. Subsurface and production data of these wells available in the public domain formed the basis for the project team to recommend an infill drilling program to maximize the value of the company's current acreage position.
The project team developed a comprehensive approach to arrive at a probabilistic production forecast and utilized subsurface data on coal gas content and bulk density available in public domain for San Juan Basin to confirm the remaining gas-in-place and need for additional takeaway points in the reservoir. Decline curve analysis was used to assess the production performance of more than one hundred infill wells drilled since 2007 and to determine the potential impact on the expected ultimate gas recovery of the offset original 160-acre spacing wells. Understanding potential interference risk was critical to justifying the need for downspacing.
The project team recommended drilling additional infill wells based on several criteria: no observation of significant interference with the majority of existing producers, considerable remaining gas-in-place that could not be developed at the current well spacing and a positive correlation between performance of Fruitland Coal wells and the thermal maturity of the San Juan Basin. The project team performed data analysis of four different type producing areas (TPAs) delineated within the basin based upon similar reservoir characteristics and production behavior. The data analysis confirmed the opportunity to drill and reduce spacing for improved recovery in areas where underlying geologic parameters like reservoir connectivity and reduced permeability has led to low recovery.