bluuebunny/crossref_metadata_2025_split huggingface dataset:
Thermally Stable Brine-Based Drill-In Fluids
Authors: Zha Weibin , Galindo Kay , Zhou Hui , Deville Jay P. 
Published: May 2015

Abstract
Reservoir drill-in fluids are specifically designed to avoid excessive fluid penetration and solid invasion into production zones so as to minimize formation damage. With wellbore temperatures increasing, the drive to develop thermally stable drill-in fluids has increased dramatically over the last few years. Oil-based or synthetic-based drill-in fluids can meet temperature requirements easily, but are often not desirable for drill-in applications. Brine-based drill-in fluids usually use bio-based polymers as viscosifiers, but they are not suitable for high temperature applications because most bio-based polymers break down at temperatures above 300°F. Most synthetic polymers available in the market are difficult to hydrate in concentrated brine solutions, and they are not so thermally stable because of hydrolysis, especially when the temperature is above 350°F. This paper describes the application of two uniquely developed polymers in brine-based drill-in fluids that demonstrate outstanding performance at temperatures greater than 400°F.
Polymer 1 is designed to work with monovalent brines, and polymer 2 is intended for divalent brines. Using these two polymers, thermally stable, brine-based drill-in fluid formulations were prepared with densities ranging from 10.5 to 18 ppg. Various brine and weighting agent combinations were investigated to keep the total amount of solids low for the various fluid densities tested. Calcium carbonate (CaCO3) was used as a bridging and weighting agent for low density fluids, and manganese tetroxide (Mn3O4) was used for high density fluids. All fluids were prepared using a multimixer, and the fluid viscosity was examined with a direct-indicating viscometer. Return permeability testing was conducted on both a lower permeability Kirby sandstone core and a higher permeability Berea sandstone core.
Both polymers provided very good rheology and solid suspension capability, as well as very good fluid loss control. The drill-in fluids made with these two polymers were statically aged at 400°F for 72 hours after conditioning the fluid by hot-rolling for 16 hours at 150°F. The viscosity of the fluids was well maintained after aging, and the high temperature (350°F/500 psi) fluid loss was less than 15mL and 10 mL for polymer 1 and polymer 2, respectively. The thermally stable brine-based drill-in fluids demonstrated high return permeability values, indicating minimal formation damage on the tested cores.
High temperature brine-based drill-in fluids are limited by the availability of thermally stable viscosifiers and fluid loss control additives. The newly developed polymers 1 and 2 provide thermal stability up to 400°F for 72 hours, which has not been achieved with previous bio-based polymers or other synthetic polymers.
Advanced Residue-Free Fracturing Fluid with Improved Friction Reduction and Exceptional Cleanup Properties
Authors: Singh Dipti , Russell Aaron , Schnoor Eli , Inyang Ubong 
Published: May 2015

Abstract
Conventional guar borate systems have historically been preferred for hydraulic fracturing applications because of the lower cost of the base polymer and crosslinker. Additionally, the fluid formulations can be easily tailored based on reservoir conditions and operational needs and the favorable tubular friction reducing characteristics of guar-based fluid systems makes them a desirable option for fracturing fluid systems. However, water insoluble residue resulting from guar-based systems may significantly impact the permeability of the proppant pack when flowing back and producing the well. A recently developed, nearly residue-free (RF) fluid system offers excellent cleanup properties and, as a result, has provided significantly improved production of hydrocarbons compared to typical guar-borate systems. While offering excellent performance and production, the RF fluid demonstrated significantly less friction reduction than comparable guar-based systems. This paper introduces a newly developed fluid system offering equivalent cleanup properties and performance, but with significantly enhanced friction reduction. The lower friction of the (LF)-RF system helps lower wellhead pressures to allow maintaining pump rate, adhering to the job design, to place the desired amount of proppant in the fracture.
This newly developed LF-RF fluid is a high performance fracturing fluid with improved regained conductivity and core permeability cleanup compared to typical guar-borate crosslinked systems. It is applicable within a wide variety of reservoirs, including unconventional reservoirs, and to-date has been successfully used in more than 1,100 stages since its introduction in early 2014. The LF-RF fluid system is applicable from 100 to 275°F bottomhole static temperature (BHST) and offers excellent operational versatility and proppant transport. This paper compares fluid performance and friction response of a conventional guar-borate fluid and the existing RF system with the newly developed LF-RF fracturing fluid.
Captain Field Injector Performance, Historical Perspective and Recent Improvements
Authors: Jones Colin , Ross Mike , Getliff Jonathan , Fuller Michael , Hiscox Ivan , Mandracchia Francesco 
Published: May 2015

Abstract
The Captain Field is situated in the outer Moray Firth in approximately 340ft water depth. The reservoirs are shallow sandstone, either sheet turbidite or channel sands. The oil is relatively viscous and is drained using long horizontal wells. The reservoir is sub hydrostatic and uses either electrical or hydraulic submersiblepumps for artificial lift.
Produced water re-injection supplemented by the field aquifer is used for voidage replacement and to maintain reservoir pressure above bubble point. The water injectors are long horizontal wells with one injector supporting a number of producers. The sand is unconsolidated and injectors are generally completed with stand-alone screens.
Since drilling the first injector well in 1995 there has been an evolution in drilling and completion practices and while the original wells were drilled with non-aqueous drilling fluids, current wells are drilled with water based fluids that have been optimized over the years. This has been an iterative process with the aim of reducing formation damage and increasing baseline injectivity.
Screen type and stimulation techniques have also changed over time and later platform wells have also been flowed back to surface which tends to greatly improve the initial injectivity. This improved injectivity is critical for the success of future field development and enhanced oil recovery deployment, which initially requires drilling of new subsea injectors. However flowing a subsea injector back to a semisubmersible rig involves significant safety and operational issues, thus new methods of increasing injectivity are being sought.
This paper will present the history of the Captain Field's injectors, explain the lessons learned over time and describe the ongoing studies that are being performed to better understand the damage mechanisms to ultimately eliminate the requirement for flowing back injector wells.
Mathematical Modelling of Non-Uniform External Cake Profile in Long Injection Wells
Authors: Kalantariasl Azim , Farajzadeh Rouhi , You Zhenjiang , Bedrikovetsky Pavel 
Published: May 2015

Abstract
Injection of colloids and suspensions in natural reservoirs accompanied with particle capture and external cake formation results in well injectivity decline. External filter cake build-up followed by stabilization is a well-known phenomenon in several engineering fields. Significant decline of the tangential rate along large intervals in long vertical wells yields non-uniform external filter cake profile. We derive the mechanical-equilibrium equations for the stabilized cake profile accounting for electrostatic particle-rock interaction and varying permeate factor. Torque balance is applied to cake equilibrium criterion and the lever-arm ratio is calculated using Hertz's theory for contact deformation of cake and particles. An implicit formula for the cake thickness along the well is derived. Two regimes of the stabilized cake build-up correspond to low and high injection rates, respectively. If the rate is below the critical value, the external cake is built up in the overall injection interval. If the rate is above the critical value, there is no cake in the upper part of the wellbore; the cake starts at the depth where the tangential rate reaches the critical value. The sensitivity analysis shows that the drag and permeate forces are the competitive factors affecting cake thickness under varying Young's modulus, rate and salinity. The main parameters defining external cake profile are injection rate, cake porosity, water salinity and Young's modulus.
New Insights into Fracturing Fluid Additives and Their Interaction in Shale Outcrop Cores Using NMR Techniques
Authors: Kim Jihye , Gomaa Ahmed , Zhang Boyang , Qu Qi , Nelson Scott , Zhang Hao 
Published: May 2015

Abstract
Oil and gas productivity from shale formations can be dependent on the flow behavior of the hydraulic fracturing fluids used in stimulation treatments. Because of the unique characteristics of shale formations, including low permeability, existence of micro-fractures, and sensitivity to contacting fluids, it is difficult to evaluate the complex microscopic interactions occurring between the fracturing fluids and the reservoir rock using traditional laboratory methods. Therefore, the objective of this study is to evaluate the interaction between fracturing fluid and representative shale cores by quantifying the invaded fluid volume during the treatment and shut-in time as a function of pore geometry using nuclear magnetic resonance (NMR) technology.
Shale outcrop cores from the Eagle Ford, Barnett, Marcellus, and Mancos were evaluated in this study. Cores were submerged in various fracturing fluids under pressure and temperature for two days. The increase in the volume of the fluid invaded into the cores was quantified using NMR as a function of the average pore radius. To mimic the flowback recovery process, the cores were placed in a vacuum cell for an hour, and the decreased fluid volumes within the cores were measured. Test conditions in this study investigated the effects of clay control additives and surfactants. Furthermore, the effect of operating parameters such as the pressure and fracturing fluid contact time was investigated.
NMR techniques enable the effective evaluation of additives, such as surfactants and clay control additives, which until now may have been selected solely based on best practices established from stimulating local conventional formations. Additionally, this comprehensive fluid evaluation technology supports the creation of customized fracturing fluids, targeted for individual shale formations, to maximize factors such as post-fracturing load recovery, and to aid in the advancement of the industry's understanding of new fracture modeling concepts.
The Impact of Formation Damage on Core Quality
Authors: Byrne Michael , Zubizarreta Izaskun , Sorrentino Yelitza 
Published: May 2015

Abstract
Formation Damage caused during drilling can have a significant impact on the near wellbore and the ability for a well to deliver to design. The reduction in near wellbore permeability is generally interpreted as a negative and the damage is normally minimised through careful selection of fluids, drilling methods and parameters. The focus on formation damage usually comes during development well planning, where optimum productivity or injectivity are required. Formation damage can also have an impact on core quality when cores are being cut and recovered to surface.
Good quality core is valued by Formation Evaluation and indeed, formation damage specialists, as it enables direct measurement of rock and fluid properties on real samples of real reservoir. It is well known that core retrieved too quickly from reservoir to surface can be physically damaged by “gas expansion”. Previous work has demonstrated that gas expansion damage should only be a major issue in low permeability reservoirs (Zubizarreta, 2013; Hettema, 2002). However, higher permeability reservoir cores can also be damaged (Worthington, 1987; Holt, 1994).
Consider the core surface and a few milimeters in to the core – mud cake and damage occur. The permeability of damaged zone is significantly lower than reservoir rock. In gas reservoirs or when bubble point is reached in high GOR, core retrieval leads to pressure difference across the damaged zone and desaturation of the mud cake damaged zone. If this pressure difference exceeds strength of rock then a thin layer of damaged rock material may develop. This fracturing of the core can render it useless for many of the normal laboratory tests conducted on core.
This paper will present evidence of structural damage developed due to formation damage around reservoir core. We will also present the modeling method used to predict this damage and give some examples of core tripping out schedules designed to protect the valuable core resource. The impact of formation damage on core structural integrity will be explored in detail for the first time and the method presented can be used to predict and avoid structural damage in future coring operations.
Acid Zone Coverage for Long Horizontal Well Stimulation Challenges and Field Case Study
Authors: Nino-Penaloza Andrea , Li Xiaohe , Gomaa Ahmed M. , Chaudhary Saleem 
Published: May 2015

Abstract
Success in matrix acid stimulation of carbonate formations depends largely on the acid distribution and the created wormhole length. Treatment design is still as much art as science, especially where field experience is used to quantify the design parameters for candidate wells. However, each well is different, and this generic approach for treatment design can result in under- or over-treating. Another challenge for long horizontal well matrix acidizing is the distribution of acids throughout a long horizontal well. Recently, controlling the perforation density and distribution has been implemented in long horizontal well matrix acidizing and proved successful in improving well productivity. This approach basically involved pumping acid through a perforated work string inside a large open-hole area. The acid distribution with limited entry into the surrounding a horizontal well is mainly controlled by perforation distribution around the work string.
In this paper, a fluid placement simulator is used to study the key parameters in optimal acid distribution with this novel limited-entry technique in long horizontal well matrix acidizing. The algorithm is based on a 2-D radial flow system that iterates time to quantify wormhole propagation and injection rate. Wormhole velocity is calculated by a laboratory empirical model that depends on two parameters measured from core flow testing. Therefore, the algorithm captures the essential physics and chemistry of the acid reaction in a carbonate porous medium. Also, this model includes such effects as multiple formation layers with independent formation parameters and allows for modeling zonal coverage, zone skin factor, and total skin factor. The main difference in terms of the improvement of formation damage from both openhole and this limited-entry completion is investigated.
The developed algorithm is a relatively simple tool that can be used by field engineers to design and optimize an acid treatment, addressing key questions such as: What type of acid and what strength should be used? What are the optimum acid volume and pump rate? What are the best diversion method and staging design? This paper demonstrates the key issues related to the interaction between the wormhole model and zonal coverage. In addition, different scenarios and a field case example are presented and discussed.
Numerical Study of Fracture Cleanup Effects and Optimization of Post-Fracture Production
Authors: Han Jiahang , Yang Junjie , Sookprasong Andy , Lafollette Randy 
Published: May 2015

Abstract
Gel damage has been identified as the most severe damage effect on gel-fractured well productivity. The reduced effective fracture length and fracture conductivity can significantly decrease the initial production rate and the ultimate recovery, especially for tight reservoirs. In this paper, we conduct numerical studies on fracture cleanup effects, and explore procedures for improving post-fracture production.
To effectively simulate fracturing fluid rheology and transportation, a dual continuum method is employed in our model. Gel residue inside the fractures is determined based on gel and breaker reaction dynamics from experimental data. Increased gel concentration in slurry injection, increased breaker concentration during fracture clean-up, and the flowback procedure are simulated to quantify the gel damage phenomenon. Features such as non-Darcy flow through fractures and polymer adsorption/desorption are included in the model. Parametric studies on the gel and breaker concentrations, reservoir properties, and flowback designs are also discussed.
Our studies determined that interactions between breaker and gel can be fully integrated into numerical simulations. Tested with a variety of gel and breaker concentrations as well as the reaction dynamics, the numerical model is robust in quantifying the gel damage phenomenon in the fracture. Detailed numerical evaluations of gel damage effects with severe gel-damage zone inside the fracture are demonstrated in this paper. High gel residue concentration is observed at the tip of fractures due to high yield stress during flowback, which reduces the effective fracture drainage. Cleanup efficiency is highly dependent on the gel and breaker interactions. Based on parametric studies, optimized gel/breaker concentrations and sufficient interaction time can significantly reduce the gel residue inside the fracture and provide possibilities of having less gel damage in hydraulic fractures. The results provide new observations about improving well productivity through proper gel/breaker selection and flowback design.
Determining the Optimum HF Concentration for Stimulation of High Temperature Sandstone Formations
Authors: Abdelmoneim Sherif S. , Nasr-El-Din Hisham A. 
Published: May 2015

Abstract
Over the years, sandstone acidizing has experienced low success rate. This makes it essential to develop a systematic method for selecting the optimum hydrofluoric acid (HF) concentration, which can achieve the highest possible permeability enhancement. Field experience and experimental studies show the significance of HF acid concentration in controlling the outcome of the treatment: adding too much HF acid will result in secondary and tertiary reactions damaging the reservoir while the use of low concentrations of HF will result in insufficient dissolution. The objective of this study is to investigate the effect of HF acid concentration and design a systematic method for designing sandstone-acidizing treatments.
Experimental work was designed to investigate the effect of the HF acid concentration, and identify the optimum concentration for different sandstone formations. Two types of sandstone cores were used in this study: Grey Berea which is characterized by low carbonate content (3 wt%), and Bandera which has a high carbonate content (16 wt%) and high content of troublesome minerals (10 wt% illite). Coreflood experiments were performed on 6 in. cores with 1.5 in. diameter. Temperatures of 280 and 325°F were used for the experiments to address the moderate and high temperature applications. HF acid concentrations varied from 0 to 3 wt% HF. Optimum concentrations were selected based on the ratio of permeability improvement. Inductively coupled plasma (ICP) was used to measure the concentrations of key ions in core effluent.
The experimental results proved the relationship between the acid concentration and mineral content. At the temperature of 280°F, Grey Berea cores, with clay content of 8 wt% and 3 wt% feldspars, the HF concentration of 1.5 wt% was able to achieve the best results. For the Bandera cores, which have a clay content of 14 wt% (10 wt% illite, 1 wt% chlorite, 2 wt% kaolinite) and 12 wt% feldspars, the acid that achieved the best results contained 1 wt% HF. When temperatures were increased to 325°F, permeability enhancement was significantly decreased while the optimum concentration remained fairly at the same HF concentration. This proves that the optimum acid concentration is independent on the temperature, but for high temperatures (&gt;300°F) retarded acids should be considered.
This work introduces the concept of designing acid treatments as a function of the mineral content. The optimum concentration of the HF was proven to adopt an inverse relationship with the mineral concentration. The proposed relationship can be used to determine the optimum acid concentration required for sandstone stimulation.
Formate Drilling & Completion Fluids: Evaluation of Potential Well Productivity Impact, Valemon
Authors: Fleming Niall , Moland Lars G. , Svanes Grete , Watson Russell , Green Justin , Patey Ian , Byrne Michael , Howard Siv 
Published: May 2015

Abstract
Valemon, operated by Statoil, is a HPHT gas/condensate field on the Norwegian Continental Shelf. Production started at the end of 2014 from a development consisting initially of cased & perforated wells. However, during early field development the orginal concept had been for stand alone screens (SAS) lower completion. K/Cs formate water based system with a density of 2.02sg. was considered as a candidate drilling and completion fluid for the wells completed with screens, one of which could potentially be suspended in formate brine for up to 10 months prior to the arrival of the platform and before clean up and the onset of production. An unknown was the possibility for any near wellbore interaction with these fluids during extended contact and the possible detrimental impact on productivity that this could have. Computational fluid dynamic (CFD) modelling was performed to determine how long formate would be in contact with the near wellbore and this demonstrated that, especially for the lower permeability intervals, a contact time of approximately 45 days was a possibility. In light of this, a sequence of corefloods was performed involving extended soaks in formate along with pre- and post test analyses to identify potential damage mechanisms. Those identified included kaolinite dissolution, precipitation of Barsium and cesium silicate, and swelling of kaolinite due to the incorporation of potassium and cesium into the kaolinite lattice. To confirm the findings from the CFD and coreflood modelling, a field review was made of Statoil's experiences with suspending wells for extended time in formate prior to clean up and production. The field review demonstrated positive experiences in using formates in suspended wells with respect to productivity. Lower than expected productivity was experienced for some wells but this could not be conclusively related to use of formates. The paper provides an overview of lessons learned from coreflooding, CFD modelling and actual field data on wells suspended in formate prior to clean-up and production.