bluuebunny/crossref_metadata_2025_split huggingface dataset:
Inhibiting Calcium Chloride Heavy Brines to be Used as Drilling Fluids: Hurdles Encountered in Treatment, Application, Corrosion Mitigation, Solubility, and Foaming Tendencies for Drilling Sites in Canada
Authors: Ariyaratna Thenuka M. , Obeyesekere Nihal U. , Jayaneththi Tharindu S. , Wylde Jonathan J. 
Published: November 2021

Abstract
A need for more economic drilling fluids has been addressed by repurposing heavy brines typically used as completion fluids. Heavy brine corrosion inhibitors have been designed for stagnant systems. Drilling fluids are subjected to both heavy agitation and aeration through recirculation systems and atmospheric exposure during the various stages of the drilling process. This paper documents the development of heavy brine corrosion inhibitors to meet these additional drilling fluid requirements.
Multiple system scenarios were presented requiring a methodical evaluation of corrosion inhibitor specifications while still maintaining performance. Due to the high density of heavy brine, traditional methods of controlling foaming were not feasible or effective. Additional product characteristics had to be modified to allow for the open mud pits where employees would be working, higher temperatures, contamination from drill cuttings, and product efficacy reduction due to absorption from solids. The product should not have any odor, should have a high flash point, and mitigate corrosion in the presence of drill cuttings, oxygen, and sour gases.
Significant laboratory development and testing were done in order to develop corrosion inhibitors for use in heavy brines based on system conditions associated with completion fluids. The application of heavy brine as a drilling fluid posed new challenges involving foam control, solubility, product stability, odor control, and efficacy when mixed with drill cuttings. The key to heavy brine corrosion inhibitor efficacy is solubility in a supersaturated system. The solvent packages developed to be utilized in such environments were highly sensitive and optimized for stagnant and sealed systems. Laboratory testing was conducted utilizing rotating cylinder electrode tests with drill cuttings added to the test fluid. Product components that were found to have strong odors or low flash points were removed or replaced. Extensive foaming evaluations of multiple components helped identify problematic chemistries. Standard defoamers failed to control foaming but the combination of a unique solvent system helped to minimize foaming. The evaluations were able to minimize foaming and yield a low odor product that was suitable for open mud pits and high temperatures without compromising product efficacy.
The methodology developed to transition heavy brine corrosion inhibitors from well completion applications to drilling fluid applications proved to be more complex than initially considered. This paper documents the philosophy of this transitioning and the hurdles that were overcome to ensure the final product met the unique system guidelines. The novel use of heavy brines as drilling fluids has created a need for novel chemistries to inhibit corrosion in a new application.
Treatment of Prodigious Reactive Shale in the Permian Basin Using High-Performance Drilling Fluid: A Successful Case Study
Authors: Alhadi Almostafa , Magzoub Musaab 
Published: November 2021

Abstract
In the Permian basin, Spraberry Trend is one of the formations that markedly contribute to the unconventional shale production in the U.S. lately. Unusual shale reactivity was encountered while drilling several horizontal wells, leading to wellbore instability issues. Consequently, shakers’ screens blockage increased the mud losses and drilling time, leading to an increased non-productive time (NPT). This paper addresses the challenges and causes of the formation instability issues resulted from shale interaction with the used drilling fluid and presents the timely actions taken to mitigate such problems.
During the drilling operation, several rock samples were collected at different depth intervals from the shale shaker. Rock samples were analyzed to identify the clay and minerals contents in the formations. The collected samples were first cleaned to remove the mud, dried, ground, and then characterized by an X-ray diffraction test (XRD) and microscopic imaging. After identifying the possible reasons for the wellbore instability, several timely actions were taken to mitigate this issue. These actions include: 1) increasing the emulsion stability, 2) increasing the water phase salinity (WPS), 3) decreasing the water phase volume, 4) adding wetting agent, 5) using wider screens for the shaker, and 6) controlling drilling parameters such as weight on bit and rotational speed. Afterward, wellbore stability, well control problem indicators, and drilling fluid properties, especially rheology, were closely monitored to identify any subsequent or unusual events.
The geological and mineralogy studies show that the drilled formation contains high smectite and illite clay content, up to 49%, which was believed to be the main reason for the unusual shale reactivity. Replacing the existing screens (200 API) with wider screens (160 and 140 API) showed an insignificant effect in mitigating the screens blockage. The adopted method of reducing the rate of penetration (ROP) and increasing the circulation time helped significantly alleviate the screens blockage by reducing the cuttings production and giving more time for hole cleaning. Furthermore, the optimal hole cleaning successfully increased the formation's stability. Adding a wetting agent to the drilling mud did not impact the cuttings aggregations; however, it led to a decrease in the rheological properties; thus, adding more concentration of the viscosifier was required to maintain the fluid rheology. Increasing the water phase salinity (WPS) to over 230k ppm and the emulsion stability to over 700 mV was considered the backbone of the treatment plan that significantly resolved the issue by inhibiting the clay. Eventually, the critical considerations were pointed out.
Implication of Turbulent Flow Induced by Gas Lift on Strontium Sulphate Scale Formation and Control Within Production Tubing
Authors: Fyfe Andrew , Nichols David , Jordan Myles 
Published: November 2021

Abstract
Sulphate scale can be predicted from thermodynamic models and over recent years better kinetics data has improved the prediction for field conditions. However, these models have not been able to predict the observed deposits where flow disruptions occur such as chokes, gas lift and safety valves. 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 with increased turbulence there is an increase in the mass of scale observed and an increased concentration of scale inhibitor is required to prevent its formation.
In this paper a field case is investigated where strontium sulphate was observed in a location downstream of a gas lift valve. Laboratory tests were conducted to confirm whether the expected scaling was observed in a low shear flow loop and also to investigate whether the location of the scale changed when additional turbulence (gas injection) was introduced to the system. The flowrate was chosen so that the shear stress generated on the test piece was approximately 1-2 Pa, similar to the value expected in typical field pipe flow. At the end of the test, the scale adhered to each of the five sections of the test piece pipe work was analysed separately to give data on both the mass and location of scale. A second test was also carried out to investigate the effect shear and turbulence induced by gas lift had on scale formation by modifying the test piece to introduce a flow of gas into the system. The test method was then used to evaluate a scale inhibitor and assess whether its performance was affected by the different flow regimes.
The introduction of the ‘gas lift’ had a significant effect on the location of scale. Instead of being spread evenly throughout the test piece, the majority of the scale deposited upstream of the gas injection point. This is likely due to the induced turbulence and expansion in the tubing diameter at the T-piece increasing the residence time and thereby enhancing scale growth. A significant difference in scale location was also observed when the inhibitor dose was too low to prevent deposition and a higher dose was required to achieve complete inhibition in the ‘gas lift’ system.
The findings from this study have significant impact on the design of test methods of evaluating scale risk in low saturation ratio brines and the screening methods for scale inhibitor for field application that should be utilised to develop suitable chemicals that perform better under higher shear conditions.
Research on the Relationship Between the Pore Structure Characteristics of Reservoir and Performance of Cr3+ Polymer Gel
Authors: Kang Xiaodong , Sun Zhe , Wang Xiujun , Zhang Jian , Zhang Shanshan 
Published: November 2021

Abstract
Cr3+ polymer gel flooding technology is very important for enhancing oil recovery and its field trails have obtained significantly oil increment effect. However, its laboratory physical simulation experiments are rarely carried out according to real reservoir conditions. Therefore, it is very important to carry out relevant research work.
Aiming at the reservoir condition of Bohai Oilfield (an offshore oilfield in China), the experimental studies on the pore structure characteristics of reservoir on the properties of Cr3+ polymer gel are carried out. The effect of different core permeability (500, 1500 and 5000 ×10−3μm2), clay content (4.5%, 9.0% and 18%), mineral type (kaolinite, montmorillonite and illite), oil saturation (79.2%, 65.4% and 49.3%) and dynamic gelation effect are thoroughly studied. Finally, its application is introduced and analyzed.
Research results show that, with the increase of reservoir permeability and pore throat size, the gelation effect improves. Also, the loose cementation degree is helpful for rapid gelation. In additional, with the decrease of the content of clay and oil saturation, the gelforming effect gets better. However, the dynamic gelation strength is very low in porous media. And after chemical injection, suspension of water flooding could promote the gel-forming performance. From the field test results, this technology has obtained good effect in Bohai oilfield, due to the high permeability, severe heterogeneity, loose cementation and high water cut.
In conclusion, it is very important to study on the gelation effect under the real reservoir conditions deeply. Therefore, the relevant experimental studies have been carried out comprehensively. And its mechanism are further explored. Furthermore, its field application has also been also summarized, which is vital to the success of this technology.
Optimize Internal Phase Salinity to Improve Wellbore Stability and Mitigate Lost Circulation
Authors: Zhang Jianguo , Rodgerson Alan , Edwards Stephen 
Published: November 2021

Abstract
Wellbore instability and lost circulation are two major sources of non-productive time (NPT) in drilling operations worldwide. Non-aqueous fluid (NAF) is often chosen to mitigate this and minimize the chemical effect on wellbore instability in reactive shales. However, it may inadvertently increase the risk of losses. A simple method to optimize internal phase salinity (IPS) of NAF is presented to improve wellbore stability and mitigate the increased possibility of losses. Field cases are used to demonstrate the effects of salinity on wellbore instability and losses, and the application of the proposed method.
IPS is optimized by managing bidirectional water movement between the NAF and shale formation via semi-permeable membrane. Typically, higher shale dehydration is designed for shallow reactive shale formation with high water content. Whereas, low or no dehydration is desired for deep naturally fractured or faulted formation by balancing osmotic pressure with hydrostatic pressure difference between mud pressure and pore pressure.
The simple approach to managing this is as follows:
The water activity profile for the shale formation (aw,shale) is developed based on geomechanical and geothermal information The water activity of drilling fluid (aw,mud) is defined through considering IPS and thermal effects The IPS of NAF is manipulated to manage whether shale dehydration is a requirement or should be avoided If the main challenge is wellbore instability in a chemically reactive shale, then the IPS should be higher than the equivalent salinity of shale formation (or aw,shale &gt; aw, mud) If the main challenge is losses into non-reactive, competent but naturally fractured or faulted shale, then IPS should be at near balance with the formation equivalent salinity (or aw, shale ≈ aw, mud)
It is important that salt (e.g. calcium chloride – CaCl2) addition during drilling operations is done judiciously. The real time monitoring of salinity variations, CaCl2 addition, water evaporation, electric stability (ES), cuttings/cavings etc. will help determine if extra salt is required.
The myth of the negative effects of IPS on wellbore instability and lost circulation is dispelled by analyzing the field data. The traditional Chinese philosophy: "following Nature is the only criteria to judge if something is right" can be applied in this instance of IPS optimization. A simple and intuitive method to manage IPS is proposed to improve drilling performance.
Ultra-Low Dose Asphaltene Inhibitors for Offshore Applications: Myth or Reality
Authors: Da Silva de Aguiar Janaina Izabel , Mahmoudkhani Amir , Ibragimova Samal 
Published: November 2021

Abstract
In recent years, long-distance subsea tiebacks have become a preferred field development option for deep and ultra-deepwater production. However, conditions such as lengthy umbilical systems, high pressures and variable temperatures conditions pose challenges for the continuous injection of various flow assurance chemicals. Severe operating conditions often require relatively high volumes of diluted inhibitors to be stored and injected offshore, resulting in high CAPEX costs for the installation of large topsides chemical storage tanks and their associated weight increases. Alliance Engineering estimates a deepwater platform's topsides installed costs are within the range of $35,000-$50,000/ton. It is possible to achieve significant capital cost savings on new platform designs if the dosage rates and subsequently offshore storage volumes of the highest usage production chemicals such as asphaltene inhibitors could be significantly reduced. This paper presents information on a new class of biosurfactants that are bio-based and eco-acceptable with potentials for development of ultra-low dose asphaltene inhibitors for offshore applications. Asphaltenes were extracted from chemical free crude oil samples and a curve of solubility with different ratios of heptane was obtained for each sample in order to determine the best conditions to perform the screening tests. A new class of glycolipid biosurfactants (GLP-U) was developed as an asphaltene dispersants effective at low concentrations for use in offshore applications. The new GLP-U biosurfactants are eco-acceptable and soluble in the organic solvents commonly used in offshore production chemicals. GLP-U were proved to be effective in dispersing and preventing precipitation of isolated asphaltenes at dosage rates as low as 25 mg/L (active substance), while for comparison a dodecylbenzesulfonic acid-based inhibitor provided inhibition at significantly higher concentrations (at least 40 times more).
A Quantitative Study of Sr2+ Impact on Barite Crystallization and Inhibition Kinetics
Authors: Zhao Yue , Dai Zhaoyi Joey , Dai Chong , Wang Xin , Paudyal Samridhdi , Ko Saebom , Yao Xuanzhu , Leschied Cianna , Kan Amy , Tomson Mason 
Published: November 2021

Abstract
Scale inhibitors have been widely used for barite scale control. Our group has developed several barite crystallization and inhibition models to predict the crystallization and inhibition kinetics of pure barite with different inhibitors and calculate the minimum inhibitor concentration (MIC) required. However, instead of pure barite scale formation, the incorporation of Sr2+ can be frequently found in the oilfield, because of the coexistence of Ba2+ and Sr2+ in the produced water, which can influence the kinetics of crystallization and inhibition significantly. As a result, the MIC predicted could be off significantly. Therefore, in this study, the effect of Sr2+ on barite crystallization and inhibition kinetics is quantitatively investigated to evaluate the accuracy of MIC values under various conditions. The induction time of barite with different concentrations of Sr2+ was measured by laser apparatus without or with different concentrations of scale inhibitor diethylenetriamine penta(methylene phosphonic acid) (DTPMP) at the conditions: barite saturation index (SI) from 1.5 to 1.8; temperature (T) from 40 to 70 ℃; and [Sr2+]/[Ba2+] molar ratios from 0 to 15, all with celestite SI &lt; 0. The results show that the induction time of the barite increases with [Sr2+]/[Ba2+] ratio at a fixed barite SI, T and DTPMP dosage. That means the MIC will be overestimated if it is calculated by previous semiempirical pure barite crystallization and inhibition models, without considering the presence of Sr2+. Based on the experimental results, the novel quantitative barite crystallization and inhibition models that include the influence of Sr2+ were developed for the first time as follows:
Barite crystallization model with the influence of Sr2+:
l o g 10 t 0 B a S O 4 ,   S r = ( 1.523 − 10.88 S I − 895.67 T ( K ) + 5477 S I × T ( K ) + 0.829 × [ C a 2 + ] ) + ( 0.823 S I + 85.44 T ( K ) − 0.667 ) × ( [ Sr 2 + ] [ B a 2 + ] )
Barite inhibition model including the influence of Sr2+
l o g 10 ( t i n h B a s o 4 , S r t 0 B a S O 4 , S r ) = b B a S O 4 , S r × C i n h l o g 10 b B a S O 4 , S r = ( − 2.187 − 1.411 × S I + 1329.29 T ( K ) + 0.153 × p H ) + ( 0.0983 × S I − 74.66 T ( K ) + 0.099 ) × ( [ Sr 2 + ] [ B a 2 + ] )
These novel models are in good agreement with the experimental data. They are used to predict the induction time and MIC more accurately at these common Ba2+ and Sr2+ coexisting scenarios. The observations and new models proposed in this study will significantly improve the barite scale management when Ba2+ and Sr2+ coexist in the oilfield.
Green Well Stimulation Fluids for Enhanced Oil Recovery from Tight Sand Formations: Field Wide 70+ Wells Study Over 4 Years
Authors: Shumway Martin , McGonagle Ryan , Nerris Anthony , Aguiar Janaina I.S. , Mahmoudkhani Amir , Jacobs D. Marc 
Published: November 2021

Abstract
Legacy oil production from Appalachian basin has been in a decline mode since 2013. With more than 80% of wells producing less than 15 bbl/day, there is a growing interest in economically and environmentally viable options for well stimulation treatments. Analysis of formation mineralogy and reservoir fluids along with history of well interventions indicated formation damage in many wells due precipitation of organics and a change in wettability being partially responsible for production decline rates in excess of forecasts. The development and properties of a novel cost-effective biosurfactant based well-stimulation fluid are described here along lessons learned from several field trials in wells completed in the Upper Devonian Bradford Group. This group of 74 wells, completed in siltstone and sandstone reservoirs were presenting more than 12 well failures annually across the field, which was attributed to the accumulation of organic deposits in the tubulars. Based on these cases, batch stimulation treatments using a novel fluid comprising biosurfactants were proposed and implemented field wide. The treatments effectively removed organic deposits, changed formation wettability from oil to water wet and resulted in a sustained oil production increase. Well failures were significantly reduced as a result of this program and the group of 74 wells did not have a paraffin-related well failure for 18 months. Results from this program demonstrates the efficiency of the green well stimulation fluids in mitigating formation damage, reducing organics deposition and in increasing oil production as a promising method to stimulate tight formations.
Epoxy Resin Exhibits Long-Term Durability and Chemical Stability as a Well Sealant
Authors: Sabins Fred , Apblett Allen , Shafer Randall , Watters Larry 
Published: November 2021

Abstract
The necessity to verify epoxy resin sealant's reliability for well applications is amplified as its use increases. Limited data exists to confirm resin's long-term durability or chemical stability under exposure to well fluids at temperature and pressure. This paper presents laboratory results illustrating durability and stability of epoxy resin exposed to a range of well fluids over a span of temperatures. Additionally, results of accelerated thermal degradation testing further quantify long-term thermal and chemical stability. Epoxy resins formulated for a range of remedial and abandonment applications were cured in fresh water, CaCl2 brine, and hydrocarbon at 170°F up to one year. Additional samples cured in fresh water and water containing CO2 and H2S at elevated temperatures (220°F to 320°F) for up to six weeks to produce accelerated degradation reactions allowed the assessment of resin degradation verses temperature. Thermal Gravimetric Analysis (TGA) evaluated chemical and mechanical degradation verses time at temperatures ranging from 200°C to 400°C. Arrhenius calculations were performed to forecast long term stability of resins across their intended temperature ranges. Resulting data were analyzed to develop an inclusive assessment of resin stability and durability in well environments. Results indicate properly formulated epoxy resin is a mechanically, chemically, and thermally durable sealant for well applications.