bluuebunny/crossref_metadata_2025_split huggingface dataset:
Comparative Study of Formation Damage due to Straining and Surface Deposition in Porous Media
Authors: Khan Hasan , Mirabolghasemi Maryam , Yang Hongtao , Prodanovic Maša , DiCarlo David , Balhoff Mathew , Gray Kenneth 
Published: January 2016

Abstract
The infiltration of fines into a reservoir during drilling or water reinjection and the accompanying production decline or loss of injectivity, are long-standing problems in the petroleum industry. Here, we propose a methodology that combines two different pore-scale models to better quantify formation damage. Further we validate the proposed model with core flood experiments.
We first perform an experimental study of suspension flow into sintered glass bead plugs and measure changes in porosity and permeability. Specifically, glass bead suspensions of known mono- and poly- disperse combinations of particle sizes, concentrations, and flowrates are flooded through the core plugs, while keeping the total invaded particle volume constant. The resulting changes in porosity and permeability are quantified using a CT scanner and pressure transducers, respectively.
We then establish two different numerical models (each focusing on a different mechanism/length scale) to predict permeability reduction. The first model takes a pore-scale approach that models straining of larger particles through the pore structures extracted from X-ray tomographic images of rock and grain pack samples from first principles.
The detailed pore structure output from the first model is used as an input in the second model, which is a network model. This pore network model simulates permeability impairment caused by both large and small particles deposition in porous media. Forces exerted on small particles include hydraulic drag, gravity, buoyancy, electric double layer, and Van der Waals. Particle trajectories in a converging- diverging pore throat are calculated dynamically. We incorporate surface roughness and particle-surface interaction to determine particle detachment and attachment. Pore throat structure and hydraulic conductivities are updated dynamically to account for the effect of previously deposited particles. We finally compared the experimental results to simulation predictions and found that the combined pore- scale model is capable of predicting the porosity of the invaded core only in the deeper regions of the core.
Field Application Study of Zinc Based, Low Debris Perforating Charges
Authors: Zuklic Stephen , Myers Bill , Satti Rajani 
Published: January 2016

Abstract
All perforating operations cause debris, which can lead to wellbore restrictions, choked downhole hardware, plugged perforations, formation damage and operational problems throughout the installation of the completion. As a result, the industry has taken significant efforts to develop low-debris perforating systems. Low debris perforating techniques are important in maintaining a clean and productive perforation tunnel, as well as helping to reduce the risk of operational issues associated with debris during subsequent downhole tool operations. This risk minimization becomes even more important in complex completions with long zones at high shot densities (as often seen in sand control completions), in stacked completions where perforating on top of packers is required, and in horizontal completions, where debris can't fall into a sump area.
One of the common methods for reducing the effect of perforating debris has been the use of zinc cased perforating charges. However, any low-debris system must also still create the optimum perforation in terms both of tunnel dimensions (maximum depth and diameter) and tunnel clean-up (minimum debris / reduced perm zone). Further, to maintain the connectivity of the perforation, consideration must be given to how the debris is handled after the perforating event and to potential interactions among the perforating debris and the wellbore and reservoir fluids. Extensive lab studies have examined all the effects of zinc perforating charges in these areas, but it is also critical to properly apply this to field scale applications through procedural examination.
This study seeks to examine effects of perforating debris on field mechanical operations comparing different types of perforating debris. A comparison versus conventional steel-cased charges is also presented in terms of charge performance and dynamic clean-up effects of low-debris zinc charges. Further, an examination of chemical interactions of these low-debris systems in the field will be presented, and most critically, a comparative evaluation of procedural decisions and methods will be presented to show an optimum application of lab learnings to field scale applications.
This paper also presents several case histories of wells that have been successfully completed using low debris perforating gun systems with zinc cased charges. Critical aspects of minimizing and managing debris, well productivity and other operational successes will be presented as part of the case histories.
Field Application of an Innovative, Minimally Damaging Low-ECD Invert Emulsion Fluid for Drilling and Completion of HP/HT Wells: Update on Fluid Performance
Authors: Strand Morten Holger , Lunde Odd Halvard , McMillan D. Nelson , Clinch Duncan , Wroblewski Tomasz , Fleming Niall , Hireche Sammy , Vatne Åsgeir , Karunakaran Mary , Ibragimova Zalpato 
Published: January 2016

Abstract
Previous publication SPE-174176-MS discussed the development of a novel high-pressure/high-temperature (HP/HT) organophilic clay-free (OCF) invert emulsion fluid (IEF) for first use as a combined reservoir drilling fluid (RDF) and screen running fluid (SRF) for stand-alone screen (SAS) completions. The current paper details the continued application of this innovative fluid in a total of five wells (four SAS, and one cased and perforated), and expands on the knowledge of fluid performance in the field.
Drilling performance, screen running performance, and productivity outcome were compared as previously determined on the first well. Additional finger printing was carried out to further understand the behavior of the 1.96-specific gravity (sg) OCF IEF: Downhole pressure measurements were compared to real-time hydraulic simulations, and were used to determine the actual pressure to break gels.
When drilling, all of the wells’ reservoir sections reached total depth (TD) without issue and with improved drilling performance. Rheology profiles were low throughout, delivering low equivalent circulating density (ECD) values. There were no incidents of barite sag during trips, and there was good gel development when static with gel strengths in excess of 15 pounds per hundred foot squared (lb/100 ft2, 10 min). Despite this, low flow rate testing (60 L/min) demonstrated very low downhole pressure to break gels (5 bar / 72 psi). At TD, fluid conditioning for screen running was achieved quickly (&lt;12 hours). The 610 micron (µm) SAS were run to TD without issue. Since put on production, all the SAS wells completed with OCF IEF are producing with no apparent negative impact of the OCF IEF.
The OCF IEF has now been used successfully to drill five reservoir sections on an HP/HT field, delivering a low ECD performance without barite sag. The SAS completion wells were drilled and completed in the same fluid with an enhanced drilling performance and acceptable productivity outcome. The continued use of this single combination fluid has removed the need for a fluid displacement to a costly dedicated heavy brine SRF, resulting in substantial time and cost savings to the operation.
Field Implementation of an Oil Based Carrier Fluid Improves Gravel Pack Efficiency
Authors: Strachan C. , Kaarigstad H. , Arnestad E. , Nesse O. Bernt , Gadiyar B. R. , Phatak A. , Green S. , Sandberg G. M. , Sedberg S. 
Published: January 2016

Abstract
Open hole gravel packing of reservoir sections drilled with oil based fluid is traditionally performed with an aqueous carrier fluid. This typically involves displacing oil based fluid to aqueous fluid once the gravel pack screen is in place. In reservoirs with swelling or unstable shale this approach reduces the risk associated with open hole exposure to aqueous fluid over time. However experience has shown that instability can still occur resulting in an incomplete, or even an aborted gravel pack. In addition, mixing of incompatible oil and water based fluids downhole has the potential to generate very viscous emulsions that negatively impact gravel pack efficiency and well productivity. The objective of the new technology was to maintain borehole stability, eliminate fluid incompatibility and enable a complete gravel pack.
An oil based carrier fluid has been developed and qualified using laboratory and yard scale testing. The fluid is a solids free invert emulsion that exhibits near Newtonian rheological behavior; thereby promoting settling of proppant during gravel packing. The density of the fluid is controlled by adjusting the volume fraction and density of the brine phase. The fluid has been qualified up to a density of 1.25 SG with further potential to achieve a density of 1.63 SG.
The oil based carrier fluid has been introduced on a mature field, with a long history of gravel pack completions. Progressive reservoir depletion has created operational challenges, resulting in inconsistent gravel pack performance. Consequently, several procedural changes have been implemented over time. Reservoir inclination is typically up to 50°, open hole length up to 200 meters, and bottom hole static temperature around 90°C. Gravel packs were most recently performed with a 1.10 SG aqueous carrier fluid.
The new carrier fluid has exhibited stable properties during implementation on multiple well completions. Gravel pack efficiencies have been consistently good, at 100% or higher. As a result, well productivity expectations have consistently been achieved or exceeded. The operational time for installing the lower completion compares well with the traditional approach with aqueous fluid.
The implementation of oil based gravel packs in multiple wells, allows a comparison with brine based gravel packs in the same field. It is therefore considered to be an industry first.
High-Pressure Filtration Unit for Completion and Workover Fluids
Authors: Alrashdan Mahir D. , Defrees Andrew , Carbrey Lee 
Published: January 2016

Abstract
Debris management is essential to successful completion operations. A High-Pressure Debris Unit (HPDU) was developed to maintain a solids-free environment during completion and workover operations. The HPDU protects downhole tools and equipment by keeping completion fluid and workover fluids free of damaging debris. The HPDU is utilized after the remaining drilling fluid is displaced by completion fluid. The system has repeatedly demonstrated its value in preventing foreign objects from entering the wellbore. Debris is removed from pits, valves, pumps and other equipment before those solids can enter the wellbore.
The HPDU system is installed at the standpipe and comprises a skid-mounted panel of eight high-pressure filter units which may be operated at pressures up to 10,000 psi and circulation rates up to 34 BPM with a future upgrade to 15,000 psi. The operational parameters enable the unit to operate at high flow rates and the unit is suitable for deepwater applications. Eight filter units, aligned four on each side, house 8- or 12-gauge gravel-pack screens. The system is operated one side at a time to enable uninterrupted continuous filtration downstream of the rig triplex pumps in the event one side plugs. The HPDU can also be easily by-passed to enable for sand control pumping operations and viscous sweeps.
This system was deployed and used in 60 different wells, primarily in the Gulf of Mexico. It has been in use since 2011 and the precursor system has been used since 2000 in 95 wells. The system can remove debris before entering the wellbore and captures damaging debris contained or dislodged in the tanks or transfer lines. In a case study, 5,286 bbls were pumped through one side and 4,329 bbls through the other side to capture 10.8 lbs and 9.2 lbs, respectively. The captured debris comprised predominantly iron-rich scale fragments, barite, calcite, sunflower seed hulls and bulk material.
This paper presents the advantages of the HPDU in optimizing completion and workover operations by reducing downtime and preventing damaging material from affecting the downhole equipment operation. The HPDU acts as the final line of defense in downhole debris management, protecting downhole tools and equipment by keeping completion fluid free of damaging debris. Working in conjunction with diatomaceous earth (DE) and cartridge filtration, the system removes solids before they can enter the wellbore. Case histories of the deployment of the HPDU and the recovered debris are presented.
Optimization of Asset-Wide Chemical Treatment Programs
Authors: Awny Z , Babaniyazov A 
Published: January 2016

Abstract
An effective chemical treatment program should reduce the rate of well failures while enhancing well productivity and minimizing cost. The unique challenges to achieving these goals include the variation in the downhole conditions, fluid composition, completion types and number of wells. The execution of chemical programs often relies on third party vendors with a vast resource base and proven technology. These traits, however, must be coupled with knowledge of the well history and proper oversight from operations, facilities, and production engineering groups. Managing and effectively utilizing collected data helps to move from "blanket type" chemical programs to a more targeted well-by-well approach.
This work uncovers several opportunities for improvement in already established chemical programs. It is especially beneficial for the onshore fields which are challenged with hundreds or even thousands of wells. The systematic improvement strategy applied in this study began by assessing existing data for identification of scaling, corrosion, and organic deposition problems. This allowed the Local Chemical Management Team (LCMT) to reveal gaps in the information needed for a more comprehensive understanding of formation damage and flow assurance issues. Proper identification of controlling damage type per formation and area of the field enabled redesigning of well completions, testing of water compatibilities for fracture stimulation, and customization of acid treatments with improved acid placement and production uplift.
Early attempts to collect fluid samples and integrate water, gas and solid analysis in the scale prediction modeling software revealed the critical nature of quality checks in sampling procedures, field tests, and lab reports. The lab audits and chemical program data management led to reorganization of the database structure and improvement in measuring and reporting of the results to the LCMT. The value of information gained by laboratory tests offered by the chemical provider was assessed in current field settings and communicated to engineering and operations personnel. A better understanding of organic deposits also supplemented wellbore and sand face clean outs.
Inclusion of a flow assurance focus in an established corrosion and well failure prevention program increased well productivity and decreased operating cost per well. Improvements in the database structure included utilization of historical data for treatment optimization, integration of oil, water, and gas with quantitative solids analysis, and the establishment of key performance metrics and reporting procedures. Customization of remedial treatments per zone and geographic location, in addition to a review of well histories and completions complemented production optimization practices. Awareness of flow assurance issues and chemical management programs was provided to operations and engineering staff through a number of on-site training sessions.
The Effect of Evolved CO2 on Wormhole Propagation in Carbonate Acidizing
Authors: Cheng H. , Zhu D. , Hill A. D. 
Published: January 2016

Abstract
Matrix acidizing is a commonly used stimulation technique for oil and gas wells. In carbonate reservoirs, acid is injected into the formation to dissolve carbonate rock in order to create highly permeable channels called wormholes. For a constant volume of acid injection, different injection rates create wormholes with different lengths. The injection rate that creates the deepest wormhole is called the optimal acid injection rate. Optimal injection rate is determined in laboratory experiments by measuring the pore volumes to breakthrough – the volume of acid injected in a core flood for the wormhole to reach the exit end of the core, normalized by the initial pore volume of the core. HCl is commonly used for carbonate acidizing treatments. The reaction between HCl and CaCO3 createsCO2. At laboratory conditions, 1000 psi back pressure is commonly used for acidizing experiment to keep CO2 in solution. However, based on the solubility of CO2 in water, 1000 psi may not be enough to keep CO2 in solution. In such a case, undissolved CO2 can be present as a gaseous phase in the system. As the properties of CO2 change with pressure and temperature, in order to accurately evaluate optimal acid injection conditions, the evolution of CO2 and its effect on wormhole propagation efficiency need to be investigated.
In this study, we conducted core flooding experiments to examine the effects of evolved CO2 onwormholing behavior. The experiments were conducted at both room temperature and at an elevated temperature. Different back pressures from 500 psi to 3000 psi were applied in the experiments. The Buijse-Glasbergen model was usedfor curve fitting to obtain the optimal acid flux and optimal pore volume to break through for each experiment. Computerized Tomography (CT) scan images were taken for each core sample after acid injection to evaluate the structures of the wormholes.
The test results show that the effect of CO2 on wormholing depends on the temperature, pressure, and injection rate. For low injection rate, CO2 present as a gaseous phase slows down wormhole propagation efficiency dramatically and enlarged wormhole diameter is observed. At injection rates above the optimal rate, the effect of CO2 is less pronounced, particularly at higher temperatures.
Experimental and Numerical Investigation of a Novel Technique for Perforation in Petroleum Reservoir
Authors: Zheng L. , Rahman M. A. , Ahammad M. J. , Butt S. D. , Alam J. M. 
Published: January 2016

Abstract
Formation damage in petroleum reservoirs is a combination of many complicated phenomena. The formation damage reduces the productivity index significantly. The damage mechanisms may occur from the stage of drilling process to tertiary oil recovery stage. This study investigates the formation damage of petroleum wells due to shooting in well completion. The study is conducted with numerical and experimental investigations. The experimental set is a prototype. Two techniques are considered for numerical simulations: one is ANSYS-CFX and other one is a computational methodology which is based on weighted residual collocation method. Single phase and two-phase flows in porous media have been taken into consideration to explore the productivity index, which is affected by formation damage. Therefore, a better understanding of damage mechanisms for various reservoir conditions can lead to optimize oil recovery rate.
Stochastic Analysis of Inorganic Scale Buildup in Seawater Injection of Waterflooding Operations
Authors: Temizel Cenk , Tiwari Aditya , Tuna Tayfun 
Published: January 2016

Abstract
Started in the late 1800s in the US, water being relatively inexpensive and readily available in large volumes and as being very effective at significantly increasing oil recovery, waterflooding has been the most common secondary recovery method applied throughout the world, contributing to pressure maintenance in the reservoir and displacing the oil phase. While there are several parameters that influence the performance of a waterflood, water quality is one of the important factors as it may cause scaling in the injection wells as well as some formation damage through chemical phenomena such as cation exchange in the reservoir resulting in decreased the recoveries.
As waterfloods continue over decades, prevention of scale formation becomes a more significant factor that needs to be properly treated. The precipitation of inorganic scale is a major issue in injecting brines with a high concentration of divalent ions. The scaling tendency of water is highly correlated with the hardness of the injection water.
Following corrosion, insoluble iron precipitates can cause damage in injection wells where precipitates can lead to severe reductions in well injectivity. Water needs to be treated in a proper way if the water contains high concentrations of calcium, magnesium or iron. In most waterflood applications, seawater needs to be used and this phenomenon is also an issue when injecting seawater into formations that contains brines with high salinity.
In this study, a comprehensive analysis of this common problem is provided by investigating the significance of parameters affecting the severity of the scale through utilizing a seawater scale buildup model to be simulated using a commercial simulator along with an in-depth review of previous studies.