bluuebunny/crossref_metadata_2025_split huggingface dataset:
A New Diversion Technique to Remove the Formation Damage from Maximum Reservoir Contact and Extended Reach Wells in Sandstone Reservoirs
Authors: Ba Geri B. S. , Mahmoud M. A. 
Published: June 2013

Abstract
Maximum reservoir contact and extended reach wells have been widely used to maximize the well productivity. The horizontal section could be 6000 ft or more in those wells, which make the damage caused by the drilling fluid varied from one section to another in the long horizontal section. The process of diversion of the stimulation fluid in carbonate wells with the same features has been performed using Viscoelastic surfactant (VES) and polymers based hydrochloric acids. In sandstone wells we cannot use either VES or polymers because there is no enough calcite to react with these fluids to produce the gel diverting materials. Also, VES could be adsorbed on the sandstone surface and cause more damage to the formation, and the use of HCl in sandstone formations has been proved to be more damaging than removing the damage.
In this paper we will introduce a smart fluid that can be used to remove the damage caused by calcium carbonated weighted drilling fluid from the maximum reservoir contact (MRC) and extended reach wells without adding any gelling materials. This fluid will react with carbonates in the sandstone formation and will produce high viscosity that will divert the flow through the less permeable part in the horizontal sections. The proposed fluid is HEDTA (hydroxyl ethylene diamine tri acetic acid). Sandstone cores were used in the coreflooding experiments, and the stimulation fluid viscosity will be measured before and after the flooding. Parallel coreflooding technique was used to confirm the diversion ability of this chemical through two sandstone cores with different permeabilities.
The experimental results showed that the viscosity of the stimulation fluid increases at least 3 times after the treatment of the sandstone cores and the parallel coreflooding showed a good ability of diversion for the fluid. The experimental results were used to describe the process of diversion using this fluid mathematically in this. HEDTA chelating agent showed good ability to remove the damage caused by drilling fluid from different permeability contrast set of cores.
The Effect of Different Brine Solutions on the Viscosity of VES Micelles
Authors: Gurluk Merve R. , Wang Guanqun , Nasr-El-Din Hisham A. , Crews James 
Published: June 2013

Abstract
Viscoelastic surfactants can provide viscoelastic properties in brines at high temperatures (higher than 230°F). Recent studies have shown the advantages of use nanoparticles in VES fluid systems. The nanoparticles have large surface area as well as unique surface morphology and surface reactivity. They can strengthen the micelle-micelle interactions. A small concentration of these particles can maintain viscosity at higher temperatures (up to 300°F) and decrease the rate of VES fluid leakoff (Huang, Crews and Willingham, 2008).
The viscoelasticity of nanoparticle-networked VES fluid systems was analyzed with a HP/HT viscometer. A series of rheology experiments have been performed by using 4 vol% amidoamine oxide surfactant in KCl, NaCl and CaBr2 brines at temperatures up to 275°F and a shear rate of 10 s-1. The nanoparticles evaluated were MgO and ZnO at the concentration of 6 pptg. In addition, the effect of different nanoparticle concentrations (0.5 to 10 pptg) on the viscosity of VES fluid was investigated. The oscillatory shear rate sweep (100 to 1 s-1) was performed from 100 to 200°F. The effect of an internal breaker on the viscosity of VES micelles was examined.
Formation Damage and the Importance of a Rigorous Diagnostic: a Case History in Nigeria Deep Water
Authors: Furgier Jean-Noël , Lebecq Cédric , Degos Xavier , Martin Frédéric 
Published: June 2013

Abstract
Total operate a field located 150 kilometers off the Niger Delta at a water depth of 1,400 meters. This field is the first deep-offshore development involving light oil with high gas content. In the field's Miocene reservoir the fluid is under saturated (~ 80 bar) and in ‘critical conditions’, i.e. the gas and liquid hydrocarbons are in a single phase, at high pressure and temperature.
Several turbiditic-type reservoir layers are developed with 22 oil producer wells, 20 water injector wells and 2 gas injector wells.
Reservoir G is a lobe sand body with good petro-physical characteristics (Permeability = 300 to 500 mD, Porosity ~ 20%). This reservoir is developed with 2 producer wells, well 7 and well 9, completed with frac-packs, and 2 water injector wells for pressure maintenance.
In September 2009, six months after first oil, well 7 and well 9 lost 70% of their potential following the decline of their productivity index. The impact was 20,000 bpd production shortfall.
This paper describes the investigation process that was conducted to identify the cause of the decline. The process included pressure transient analysis, geochemical analysis, core flooding tests and scale modeling. A trial and error approach was adopted when designing well intervention in order to get as much information as possible and firm up the most realistic cause of production damage.
This paper also highlights the fact that a proper diagnostic requires a multi-discipline approach, an open mind and a comprehensive risk analysis.
Stand Alone Screens: What Key Parameters are Really Important for a Successful Design?
Authors: Furgier Jean-Noël , Viguerie Bjorn , Aubry Eric , Rivet Pascal 
Published: June 2013

Abstract
Stand alone screens is a sand control technique that has been widely used in the industry for many years. However, some failures have been experienced, raising some concerns about the validity of design and operating procedures. Contrary to gravel pack for which Saucier criteria is well accepted, design criteria for a sand screen only has always been subject to discussion. As it is a simple and cost effective sand control solution, there is still an incentive to develop more robust design and installation rules.
Within Total, a large experience was built in running stand alone screens that allowed optimizing installation practices. In addition, a multi-year laboratory experiments program was run to establish the key parameters in designing stand alone screens. Results of this work are discussed in this paper.
First, an experimental work flow was developed and made reliable after evaluating consistence and repeatability of results.
Then, a sizing criteria based on the retention of the largest sand grains was confirmed to be pertinent.
At last, it was demonstrated the sand size distribution does not have any impact on the sand retention performance of a screen. It cannot be the origin of screen plugging.
This work will set new standards in stand alone screen design in Total.
Development and Applications of an Aqueous-Based Surface Modification Agent
Authors: Vo L. K. , Nguyen P. D. , Weaver J. D. 
Published: June 2013

Abstract
Surface modification agents (SMAs) were developed more than fifteen years ago to agglomerate proppant to reduce proppant flowback, prevent fines invasion and migration, and improve fracture conductivity. The instant onset of extreme tackiness and insolubility of SMAs can present operational challenges with respect to maintaining and cleaning fracturing equipment. This paper presents the laboratory development and field implementation of a new, aqueous-based surface modification agent (ASMA) that addresses operational challenges and provides superior economic benefits with low health and environmental risk. New potential uses resulting from slow onset of tackiness are also presented.
An ASMA is a water external emulsion having an SMA contained within the internal phase. This ASMA is applicable for all of the same uses as solvent-based SMAs, such as on-the-fly coating of proppant during fracturing, frac-packing, or gravel-packing. One new application made possible by emulsion delivery is the inclusion of the ASMA in the first fluid injected into a fracture, which coats the fracture face with a hydrophobic film. This film provides stability to soft formations, inhibits water invasion, minimizes damage attributed to formation spalling, and improves proppant distribution by causing proppant to adhere to the frac face.
ASMA is aqueous based, and can be diluted in brine for deep injection into existing proppant packs. This enables its use for remedial treatments to repair fines-damaged frac-packs where frequent acid treatments are required to maintain acceptable production. Laboratory optimization of acid stimulation and remedial fines-control treatment designs are presented.
New emulsion technology allows SMA release to be delayed so that the extreme tackiness and insolubility does not damage mixing equipment, and can be easily cleaned. In addition, the delayed delivery of the SMA permits direct injection into proppant packs and the formation matrix to provide for remedial fines treatments, resulting in longer lasting acid stimulation of frac-pack completions.
Viscoelastic Evaluation of Gemini Surfactant Gel for Hydraulic Fracturing
Authors: Yang Jiang , Guan Baoshan , Lu Yongjun , Cui Weixiang , Qiu Xiaohui , Yang Zhen , Qin Wenlong 
Published: June 2013

Abstract
The viscoelastic surfactant (VES) fluids have been used in stimulation of low permeability oil and gas reservoir due to their low formation damage. The physical association and entanglement of wormlike like micelle gives viscoelastic properties, which gives similar properties as polymer. However, conventional viscoelastic surfactant fluids were used at much higher concentration than that of traditional polymer guar fluids. The more effective VES fluids that performed at lower concentration are unmet needs to be filled. Hence, new cationic Gemini viscoelastic surfactants with connecting spacer were studied. The Gemini surfactants have higher surface activity than that of conventional surfactants. Critical micelle concentration of Gemini surfactants is 10 times lower than that of conventional surfactants. Fluids of Gemini surfactants gave the desired viscosity by forming gel structure at lower concentration than that of conventional surfactants. The viscosity of new Gemini VES fluid can be maintained above 50 cps at 1% under 120 °C and shear rate of 100 s-1. The fluid is shear stable at the temperature for 2 hours. The dynamic rheological properties of the new VES fluid showed highly elastic properties, which elastic moduli G’ is higher than loss moduli G’ ‘at angular frequency 0.1 rad/s below 100 °C. It showed good proppant suspending properties. The solvent with high polarity has less effect on fluid viscosity than that of solvent with low polarity. The Gemini VES gel can be broken down upon contacting and mixing with hydrocarbons or dilution with formation brine. The Gemini VES gel is a better alterative fluid for low damaging hydraulic fracturing.
Experimental Investigation on the Effects of Very Low Salinity on Middle Eastern Sandstone Corefloods
Authors: Pingo-Almada M. B. , Pieterse S. G. , Marcelis A. H. , van Haasterecht M. J. , Brussee N. J. , van der Linde H. A. 
Published: June 2013

Abstract
Low salinity flooding (LSF)- decreasing ionic strength to enhance oil production- is an Enhanced Oil Recovery (EOR) process currently being evaluated in industry and academia with first deployment beginning. A wettability modification is assumed to take place when decreasing the ionic strength. In this work we explore the effects of varying salinities from formation water down to very low salinity on brine permeability and on effluent composition. The following effects have been investigated: the presence and absence of oil in the core, the cation exchange capacity (CEC), mineral dissolution and cation stripping. The experimental component of this investigation consisted of continuous permeability measurements during flooding at various salinity steps and simultaneous collection of the effluent. The effluent was analyzed using Inductively Coupled Plasma (ICP elemental analysis). The CEC's of the rock exposed to the different salinities have also been measured. Scanning Electron Microscope (SEM) visual investigations have also been carried out.
During the flooding with several different brines, permeability variations were observed. The variation of the ionic composition of the effluent has allowed for:
identification and characterization of the temporary divalent cation stripping process the framing of hypotheses about other possible mechanisms taking place in the core during LSF, such as: ○ion exchange between injected brine and the clays as the salinity decreased○The role that CEC plays in the re-equilibration with the new salinity○the CEC variation throughout the experiment at Sor○mineral dissolution and clay deflocculation. The comprehensive suite of tools and techniques used here has given more insights into the mechanisms taking place when decreasing the ionic strength and their use can serve to improve the deployment of the technology, including the prevention of formation damage.
Using Hydrochloric Acid to Remove Ilmenite Water-Based Filter Cake in HPHT Applications
Authors: Elkatatny S. M. , Xiao J. , Nasr-El-Din H. A. , Al-Bagoury M. 
Published: June 2013

Abstract
The growing demand for well-designed weighting agents to overcome the currently drilling challenges such as ECD management and the settling tendency of the weighting agents led to the development of a new micronized ilmenite (FeTiO3). The acid solubility of ilmenite is of great importance to remediate any damage that might occur during its use in the drilling operation.
Extensive lab work was conducted to: 1) assess the reaction of 10 wt% HCl with ilmenite particles at 300°F and 300 psi using an aging cell, 2) optimize the concentration of HCl to remove the filter cake using a modified HPHT filter press at 250°F, 3) determine the removal efficiency of the filter cake, and 4) calculate the retained permeability of Indiana limestone cores.
The reaction of hydrochloric acid with ilmenite showed that HCl (10 wt%) dissolved 75 wt% of the iron from ilmenite particles after 10 hrs of reaction at 300°F. SEM and XRD results showed that the reaction product was mainly rutile (TiO2) after 6 hrs of reaction.
Ilmenite-based filter cake was removed completely after reaction with 5 wt% HCl (300 g solution) for 16 hrs soaking time at 250°F. The retained permeability of the Indiana limestone and Berea sandstone cores was nearly 100% after HCl treatment (5 wt%). Removal of ilmenite water-based filter cake is a simple process as compared with barite water-based filter cake, which cannot be removed using HCl. This study will provide a complete evaluation of the reaction of HCl with ilmenite and will help the drilling and completion engineers to better design the chemical treatments to remove the filter cake for HPHT wells.
Evaluation of Micronized Ilmenite as a Weighting Material in Oil-based Drilling Fluids for HPHT Applications
Authors: Xiao J. , Nasr-El-Din H. A. , Al-Bagoury M. 
Published: June 2013

Abstract
Ilmenite (FeTiO3) with a mean particle size of 30 – 45 um was first introduced into the oil industry as weighting material in 1976. However, its use was limited mainly because of its abrasiveness to drilling equipment. Recently, a superfine ilmenite (5 μm) was introduced to address shortcomings of the traditional weighting materials. The objective of this study is to discuss the performance of oil-based drilling fluids using ilmenite as a weighting material for HPHT applications.
Oil-based drilling fluids with a density of 1.92 SG containing API standard barite and ilmenite were compared. HPHT filtration tests under static and dynamic conditions were conducted at 300°F and 300 psi. Indiana limestone cores with an average porosity of 23 vol% and an average permeability of 100 md were used in the filtration tests. The rheological properties, sag tendency, the volume of filtrate, and the filter cake thickness of the oil-based drilling fluids were determined before and after heating at 400°F for 16 hours.
Results showed that ilmenite-based drilling fluids had a sag factor of &lt; 0.3 and a plastic viscosity of 25–30 cp, much lower than those of barite. HTHP filtration tests showed that under static conditions, the filter cake had a thickness of 0.18 in. and 2.9 cm3 of filtrate volume; while under dynamic conditions, the filter cake thickness was 0.15 in. and the filtrate volume was 2.2 cm3. The rheological properties of oil-based drilling fluids were constant after heating at 400°F for 16 hours. The filter cake thickness and sag factor were small even after 16 hours of heating. This study provides an evaluation of oil-based drilling fluids with ilmenite as a weighting material for HPHT wells, and gives recommendations on how to use it in the field.
Formation Damage in the Cavendish Gas Field - Causes, Treatment and Future Measures
Authors: Kersten Christoph , Schulze Kai , Schroers Florian , Mandiwall Darrell , Jeffs Paul 
Published: June 2013

Abstract
The Cavendish gas field is located off-shore in the Southern Gas Basin of the UK North Sea. The Westphalian and Namurian Fluvial Sandstones are at a depth of circa 11,500 ft (3,500 m). The wells showed an initial reservoir pressure of 6,100 psia (420 bara) and a temperature of 230 °F (110 °C). During gas production starting in 2007 the initial gas production rate of 60 to 70 MMscf/d per well decreased significantly after seven months of production. The condensate-gas-ratio was between 3.5 and 11.0 stb/MMscf for the two active producers. During a well work-over at the end of 2010, down-hole solids and liquid samples were taken for analysis to identify possible formation damage processes. The solids were identified by x-ray diffraction as rust and scale, mainly carbonate scale. The liquids were characterized by gas chromatography as hydrocarbon condensate, with no trace of residual drilling mud. Two formation damage or productivity impairment mechanisms were identified; scaling and hydrocarbon banking.
Scaling Carbonate scale was caused by the interaction of reservoir brine and the high concentration of carbonate ions in the high pH K-formate drilling fluid. Due to the comparatively long exposure times (ca. 16 days) and thermal degradation of the drilling fluid, hydrogen-carbonate ions were formed and because of the relatively high calcium content of the formation water and presence of ferroan dolomite as intergranular cement within the matrix, carbonate scale was precipitated. Hydrocarbon Banking Liquid hydrocarbons condensed as a result of the lean-retrograde gas condensate character of the reservoir fluids and reservoir pressure decreasing below the respective dew point pressures. This was confirmed by the interpretation of the PVT and fluid compositional analysis with computational software tools.
In order to restore productivity, the reservoir section of the two affected wells was milled and re-perforated. After this treatment their productivity was observed to increase significantly. A proactive scale inhibition treatment for the future was not regarded as necessary because all technical (non-formation) fluids were removed and the wells are not regarded as significantly self scaling. Alsothe reservoir pressure had decreased sufficiently to prevent any severe further retrograde hydrocarbon condensation in the wellbore area.
"Dope-Free" Tubulars in Petroleum Well Completions
Authors: Funes Alejandro , Figini Fernando , Goretta Emiliano Actis , de Franceschi Esteban , Benedetto Fabián , Castiñeiras Tomás , Economides Michael J. 
Published: June 2013

Abstract
"Dope", an inorganic compound, has been used routinely during well construction for both casing and tubing to lubricate, seal and protect against corrosion of segment-connecting threads. During the well tubular assembly a portion of the thread compound is exuded inside and outside the connection and gets access to the well fluids through the tubing and annular space. Studies presented here show that the dope forms a suspension which penetrates and damages the formation. The studies used standard fluid circulation velocities during typical completion operations. The formation damage is severe (more than 99 percent) and has been confirmed with a number of core-test experiments, presented in this work.
If the well is put on injection service and in the case of workovers such as matrix stimulation treatments, the formation damage caused by pipe dope will almost guarantee operational failure. For production the issue is different and will depend on the reservoir permeability and the ability or lack thereof of the dope compound to penetrate the rock matrix or whether it will form a removable filter cake.
Recent innovative technologies have allowed the introduction of dope-free connectivity by engineering the connections at the end of pipe sections. Avoiding the use of dope compounds has apparent benefits, one of which is the prevention of well damage. Another is the efficiency and reliability of the operation itself, removing a cumbersome, albeit routine job, a major advantage in the hectic time of a drilling rig's operation. An important side benefit are improvements in the Health & Safety indicators of the casing & tubing installation- as the number of operations to install these is significantly reduced and also on the Environmental side, as the dope-free connections produce zero effluents, the connections being "ready-to-run" from the factory.
We present here the clear benefits of using dope-free pipe connections by quantifying the negative effects of the alternative. Production equations using a dope-induced skin effect are presented, showing the detrimental impact on well performance.
An Environmentally Acceptable and Non-damaging Diversion System for High-Permeability Formations
Authors: Patnana Vijaya K , Karadkar Prasad B , Choudhary Yogesh Kumar 
Published: June 2013

Abstract
Uniform zonal coverage of the entire treatment interval is essential to the success of matrix stimulation treatments, especially for long intervals with high degrees of heterogeneity. In such cases, without effective diversion, the injected fluid will follow the path of least resistance, and very little treatment fluid will enter into low-permeability or highly damaged zones. However, effectively and economically diverting fluids from high-permeability zones to low-permeability zones has always been a challenge.
In this paper, a new non-damaging diversion or fluid-loss-control system is discussed that provides high differential pressure for the fluid flow by forming a low-permeability filter cake on the formation face or bridging the perforation tunnel, or by plugging pore throats, which helps divert fluid to other zones. The system consists of degradable polymer particulates and food-grade legume particulates whose particle size is relatively smaller than the polymer particulates. The laboratory test results show that the system provides good leakoff control and sustained a differential pressure as high as 2,300 psi. This system can be used in both non-acidic and acidic (up to 15% hydrochloric [HCl] acid) medium for temperatures up to 250°F. The effects of temperature and carrier fluid on the performance of this system are discussed.
The mixing procedure for preparing the blend, high-pressure/high-temperature (HP/HT) filter-press experiment setup, test procedure, results of experiments, and degradation behavior of the materials used in the system are described. The newly proposed system is suitable for various applications, such as (1) diversion during matrix treatments of long intervals, (2) fluid-loss or lost-circulation control, and (3) plugging of natural fractures.