bluuebunny/crossref_metadata_2025_split huggingface dataset:
Reservoir Friendly Rigid Setting Fluid Arrests Lost Circulation While Minimizing Reservoir Damage
Authors: Savari Sharath , Whitfill Donald L. , Miller Matthew L. 
Published: June 2014

Abstract
Currently, many producing formations are carbonates and/or depleted sands that are characterized by highly permeable flow paths or vugs. Severe-to-total loss of drilling fluid in these formations is a major concern from both the drilling and reservoir damage perspectives. Conventional particulate lost circulation materials (LCMs), such as acid-soluble ground marble, might not effectively cure severe losses. Furthermore, because the application is in a producing formation, avoiding reservoir damage is a major criterion that any potential solution should satisfy. The "band-width" of available solutions that are both efficient and reservoir friendly is narrow, leading to both high cost and potentially risky drilling practices.
A possible solution is using an acid-soluble right-angle-setting composition (RAS-Co) that was developed to provide the industry with a more efficient solution for plugging and isolating producing zones that have high drilling fluid loss rates. RAS-Co is formulated from inorganic, nonhazardous powders and fluids mixed in fresh water or seawater. RAS-Co is engineered to be a low-viscosity (18 to 30 cp) fluid containing small particulates, which allows it to be mixed at the rigsite and pumped through any drillstring configuration. It is designed to react at a specific bottomhole circulating temperature (BHCT) in a consistent and controllable manner with a "right-angle" set. Once it is spotted/placed in the suspected loss zone, it helps eliminate further fluid losses and formation damage. The small particle size distribution acts as a pore-bridging material while in the fluid state, and the right-angle-set characteristic makes the material non-invasive to the formation and allows it to be easily drilled or removed with acid. It can be used in zones with up to 300°F circulating temperature and tolerates up to 50% contamination with water or drilling fluids.
This paper describes attributes of RAS-Co along with successful field applications that illustrate it is an effective solution for controlling reservoir damage by helping to stop severe lost circulation events.
Reservoir Simulation, Ion Reactions and Near-Well Bore Modelling to Aid Scale Management in a Subsea Gulf of Mexico Field
Authors: Mackay Eric J , Jordan Myles M. , Ishkov Oleg , Vazquez Oscar 
Published: June 2014

Abstract
This paper presents the findings of a study into the impact of reservoir flow behaviour on both the scaling risk at production wells, and the options for managing this scaling risk, for a deepwater sandstone reservoir in the Gulf of Mexico. One significant feature in this field is that flow takes place through isolated formation layers, and choices made regarding the seawater injection wells have a great impact, not only on the BaSO4 scaling tendency, but also on the placement of scale inhibitor squeeze treatments in the producers. In addition to seawater injection, oil production is supported by the aquifer. The first stage of this study involved identifying the split between connate, aquifer and sea water in the produced brine. This provided data that could be used to calculate the evolution of the scaling risk over the lifecycle of each well. The formation brines contain barium and the injection water is full sulphate seawater, and the relative proportion of each brine, the water production rate, and pressure and temperature conditions all determine the scaling risk. The evaluation of the extent of reactions between the injection water (sulphate) and formation water (barium) from injection to production well can result in a significant reduction in the available barium within the produced water, and hence the scale risk and scale inhibitor concentration required to prevent scale deposition. In this study, as the injection wells were completed with inflow control devices (ICD's) it gave the opportunity to manage the injection split via these ICD's, not only to improve sweep efficiency, but also to balance reservoir pressures and make squeeze treatments more efficient. The study will present the squeeze treatment volumes and estimated treatment lifetimes possible for two scenarios for the water injection application to this deepwater field. The implications of this type of study will be highlighted in terms of the options that this data allows an operator to consider prior to commissioning water injection in these challenging environments.
Rig Time Was Saved in a Remote Two -Rig Operation Completing Horizontal Openhole Wells with Expandable Sand Screen Through Careful Selection and Aggressive Juggling of Multiple Reservoir Drill-In Fluids
Authors: Luyster M. , Anez M. J. , Brzezinski M. A. , Nguyen C. , Ravitz R. , Bumala P. L. 
Published: June 2014

Abstract
A drilling and completion program was developed for a two-rig deepwater completion campaign in West Africa that included openhole water injectors and oil producers drilled in a highly unconsolidated sandstone reservoir with permeability that ranged from several Darcy to tens of Darcies. The limited storage onshore and discharge options mandated recycling fluids from well to well.
To minimize rig time on the two semi-submersibles, a plan was developed to juggle the five required fluid systems:
an oil-based drilling system for the uphole sections a reservoir drill-in fluid a screen-running fluid a breaker system a clear completion brine
Each system was designed and tested during the planning stage to meet project objectives. For the expanded sand screen application, the 8½-in. hole diameter could not be washed out more than 9¼ in. Wellbore stability required the drill-in fluid to be at least 10.8 lb/gal to control the shale and avoid hole eccentricity. Fluid rheology was critical as circulating density could not exceed 12.3 lb/gal to stay below the predicted 12.5-lb/gal fracture gradient, and good hole cleaning was essential in the horizontal sections that reached out to 1,000 m.
When running the screen, particulates in the mud had to pass through the 150-μm mesh otherwise the screen would plug and ultimately collapse. To attain the required weight, the screen-running fluid utilized fine micron-grind barite to attain density while avoiding screen plugging. Once the screen was in place and expanded, a delayed breaker was spotted in the screen to eventually dissolve the carbonate filtercake left behind by the drill-in fluid. The well was then displaced to completion brine. Reducing cross contamination during these displacements was important to avoid costly disposal.
The unique chemistry and properties of these systems demanded a comprehensive fluid management and quality control plan that began with product procurement, through the warehouse and mixing plant, onboard the supply vessels that stored these fluids, and final transfer and use on the rigs. Avoiding cross contamination and preservation of each of the different fluid for each successive well was crucial to minimize damage to the target sand, reduce rig time, and to reduce overall cost.
Development of a New Squeeze Scale Inhibitor for Mitigating Formation Damage for High TDS High Temperature Tight Carbonate Reservoir
Authors: Chen Tao , Lewis Jennifer , Chen Ping , Benvie Ronald , Hagen Thomas , Montgomerie Harry 
Published: June 2014

Abstract
The development of effective scale squeeze inhibitors in tight carbonate reservoirs with permeability less than 5md is still a big challenge, especially for high Total Dissolved Solids (TDS) and high temperature wells. The formation damage is one of the major considerations in high TDS, high temperature, and tight carbonate reservoirs as it can be caused due to fines mobilization, carbonate reservoir dissolution and collapse, and scale inhibitor compatibility issues. For the development of any scale inhibitor for squeeze application, the product must also demonstrate good inhibition performance, long squeeze life and accurate residual analysis at low concentrations.
This paper will demonstrate a logical design procedure to develop a new scale inhibitor suitable for a challenging high TDS, high temperature tight carbonate reservoir through squeeze application. The new scale inhibitor has been shown to be nondamaging to tight carbonate reservoir material under high temperature high TDS conditions, along with excellent retention and release characteristics. The results of a comprehensive testing program, including compatibility, formation dissolution, dynamic tubing blockage and core flood tests will be presented that will highlight the development of a non-formation damage scale inhibitor suitable for the high TDS high temperature tight carbonate reservoir.
In addition, the potential mechanisms of formation damage will be addressed. The impact of calcium tolerance, pH and molecular chemistry, carbonate reservoir dissolution and lab test procedure will be discussed compared to some traditional phosphonate and other polymeric scale inhibitors.
Advanced Understanding of Matrix Stimulation Treatments Through In-Job and Post-Job Evaluation of Real-Time Downhole Measurements with Coiled Tubing: A Case Study
Authors: Ahmed Danish , Ramondenc Pierre , Baez Fernando 
Published: June 2014

Abstract
Matrix stimulation treatments executed with coiled tubing (CT) face various challenges in terms of design, execution, and evaluation. The design phase typically relies on information that is frequently poorly known (e.g., extent of damage). Treatment pumping schedules and fluid concentrations are often determined based on previous experience and accepted local practices. For the execution to be completed within a safe framework, the standard is to keep pumping pressures below the fracturing pressure. In some cases, tools like high pressure differential jetting nozzles are used to provide deeper penetration and lower breakdown pressures. The depths at which those tools are operated usually depend on a prior log interpretation. Finally, treatment evaluation is typically limited to the comparison of pre and post-stimulation wellhead pressures and rates.
Over the past decade, numerical modeling has allowed the industry to address some of the design and evaluation challenges. Yet, the same question often remains: has the design been effectively executed and was the intervention successful? The answer depends on the choice of success criteria such as efficiency, safety, and economics.
CT enabled with fiber optic telemetry—which consists of downhole gauges providing real-time data of pressure, temperature, gamma ray, and casing collar locator—has proven a game-changing technology with respect to treatment execution, improving both intervention efficiency and safety (Jacobsen et al. 2010). The provided measurements, along with the possibility to acquire distributed temperature surveys (DTS), have also shown to be the most effective solution for treatment evaluation to date.
The case study presented here not only describes how CT with downhole sensors was used to optimize the acidizing treatment of an oil well producer and ensure its effective stimulation, but it also demonstrates how the real-time and DTS data were analyzed both during the intervention and through post-job numerical modeling, in order to refine the understanding of the well and that of its formation characteristics.
An Innovative Approach to Forecasting Matrix Stimulation Treatment Results: A Case Study
Authors: Ahmed D. , Haryanto E. , Soendoro F. H. , Baez F. , Bolanos N. , Zhou W. 
Published: June 2014

Abstract
Successful matrix stimulation engineering depends on knowledge of formation damage and its extent in causing the well not to produce to its potential. Stimulation design is a complex procedure as formation properties need to be honored when designing for sandstones, whereas for carbonates reservoirs, the presence of secondary porosity along with matrix requires a somewhat different approach. Operating companies have positive expectations for matrix treatments as they see it as a cost effective, efficient and safe approach of intervention to restore or stimulate production of a well that has formation damage.
In the oil and gas industry, diverse software applications are available to model matrix stimulation treatments but validity of such models depend on their robustness, starting with input data; i.e. formation characteristic such as permeability, porosity, pressures, temperature, skin-damage and its extent have strong impacts on the simulation results. Not very often is all of this information available; and if it exists, sometimes it's not up to date or questions may arise about the accuracy. This leads to operators to question how valid the design is and if it will allow them to meet their goals or not?
This paper describes an innovative approach that has been implemented to establish an effective stimulation design and forecast results based on execution parameters. The idea consists in using real-time downhole pressure and temperature measurements, along with Distributed Temperature Sensing (DTS) acquired during matrix stimulation execution. The downhole data is utilized to calibrate the formation and fluid characteristics via pressure matching which provides ability to determine how much of actual skin is reduced. This result is then incorporated to a reservoir model to forecast and evaluate the potential of the post stimulation production results.
Proppant Pack Permeability: Does it Matter? Field Case Histories of a Nearly Residue-Free Crosslinked Fluid System
Authors: Inyang Ubong , Fontenelle Lucas , Schultheiss Nate 
Published: June 2014

Abstract
Crosslinked polymer hydrogels are commonly used in hydraulic fracturing to provide enhanced fracture width and length, while providing the ability to suspend and transport high concentrations of proppant deep into the generated fractures. Then, during post-fracture cleanup, the gel viscosity must be reduced and the broken fluid flowed back through the proppant to the wellbore. This process should occur with minimal damage to the proppant pack so as not to restrict hydrocarbon production from the reservoir. Significant permeability damage to the proppant pack occurs if insoluble residue from the fluid becomes trapped within the pores of the proppant pack. Consequently, it is of prime importance to ensure the fluid breaks cleanly and any insoluble residue is minimized.
A new nearly residue-free (res-free) fracturing fluid was developed for use in crosslinked fluid applications. This fluid system was found to be very clean, leaving little to no residue (&lt; 1%) upon breaking, leading to improvements in well cleanup and increased hydrocarbon production. This new fluid is a polysaccharide-based material that can be formulated to provide the necessary fluid performance parameters expected from traditional guar-based systems, but without the damaging insoluble characteristic of guar-based fluid systems.
A number of successful treatments using the res-free fluid have been performed, resulting in superior production. This paper describes the fluid system, laboratory testing and results, field operation best practices, and production data from a series of wells stimulated with the nearly res-free fluid compared to offset wells.
Successful Application of a Differentiated Chelant-Based Hydrofluoric Acid for the Removal of Aluminosilicates, Fines, and Scale in Offshore Reservoirs of the Gulf of Mexico
Authors: Sopngwi Jean-Jose S. , Gauthreaux Alex , Kiburz Daniel E. , Kashib Tarun , Reyes Enrique A. , Beuterbaugh Aaron , Smith Alyssa L. , Smith Steve K. 
Published: June 2014

Abstract
The Ewing Bank 873 (EW 873) Field is an offshore mature field in the Gulf of Mexico that produces hydrocarbon from Pliocene stacked turbidite sands. Wells in the EW 873 Field have experienced production impairment from formation damage, such as aluminosilicates, fines, and scale, including calcium carbonate (CaCO3) and barium sulfate (BaSO4). This paper discusses the results of the successful application of a differentiated chelant-based hydrofluoric (HF) acid to remove formation damage and enhance oil production (by as much as 305%) from Well A-04 in the EW 873 Field. Additionally, the paper presents the chemical analyses of the acid flowback as well as the methods used to characterize the formation damage. More importantly, the paper also focuses on the research efforts that led to the development and successful application of the differentiated chelant-based HF acid.
Throughout the research, analytical experiments and corefloods were performed with different acid formulations on cores that contained acid-sensitive clays, CaCO3 and BaSO4. Two formulations contained alpha-hydroxycarboxylic (a-HCA) HF acids, and other formulations contained chelants and chelant HF acids, which were both based on an aminopolycarboxylic acid (APCA). The APCA/HF acid proved to be the most effective formulation, as it achieved the highest permeability increase (relative to brine) and dissolved ions while mitigating precipitation. Furthermore, the APCA/HF acid is biodegradable, and compatibility and corrosion testing indicated that it is compatible with the produced oil samples of Well A-04 and it exhibits low corrosion loss (&lt; 0.05 lbm/ft2) when applied with a chosen corrosion inhibitor on 13-Cr metallurgy, respectively.
The development of this differentiated APCA/HF acid highlights the potential of performing successful acid jobs where complex mineralogies, such as CaCO3 and BaSO4, are present.
An Innovative Approach for Sand Management with Downhole Validation
Authors: Subbiah Surej Kumar , de Groot Lex , Graven Hilbrand 
Published: June 2014

Abstract
Sand production caused the abandonment of two production wells out of four in a gas field located in the Netherlands sector of the North Sea. The forced two abandoned wells due severe sand production accounted for 75% of total gas production from the field. The loss production was unexpected. This paper describes how geomechanics was applied to develop a screenless completion design for one well, and cased-hole with gravel packs for three others, to re-establish economic sand-free production rates for the field.
A geomechanics study of the reservoir sections of the abandoned wells examined the mechanical properties, including rock strength and plasticity, as well as the state of stress acting on the producing sections. The study predicted the sanding history of both wells accurately. Modelling indicated that a thin sand layer with low rock strength was the main contributor to the overall sand production. This was later validated with a Downhole Sand Detector Tool. The modelling also indicated that sand production was likely from other, stronger sections of the reservoir as the field continued to deplete
Once a validated prediction of sand failure had been constructed for the reservoir, the study investigated improvements to the well design that would give both economic production rates and sand-free production for the lifetime of the field. In addition to considering geomechanical properties, the study investigated the geometry of the completion to find the most stable orientations for the wellbore and the perforations.
After an economic feasibility study, one of the abandoned wells was sidetracked along the optimally selected trajectory and perforated with oriented guns, isolating identified weak zones. The field has been producing since this remedial work without any sand production, and the missed production has been recovered. As the results, this meets the operator production and recovery objectives for the field.
A Comprehensive Approach to Estimate Invasion Radius of Mud Filtrate to Evaluate Formation Damage Caused by Overbalanced Drilling
Authors: Ling Kegang , Zhang He , Shen Zheng , Ghalambor Ali , Han Guoqing , He Jun , Pei Peng 
Published: June 2014

Abstract
Formation damage caused by overbalanced drilling (OBD) using water-based mud (WBM) is inevitable as a result of mud filtrate invading into the near wellbore formation. The invasion radius is critical to the multiphase flow when the well is put on production. It contributes to the total skin that hinders the hydrocarbon production. Furthermore, the response of the logging tools may be affected as a result of such invasion, rendering many inaccurate calculations of the formation evaluation. To evaluate the skin caused by mud filtrate invasion, it is imperative to determine the radius of invasion properly. A thoroughly literature review indicated that the previous investigations have focused on formation damage caused by drilling mud filtration, and none of them had proposed a practical, comprehensive, and reliable method, with solid theoretical base, to quantify this formation damage. This work filled this gap.
In this work, we developed a practical and comprehensive model to determine the depth of mud filtrate invasion near the wellbore. The distribution of mud filtrate saturation in the near-wellbore region is also calculated by employing drilling operation parameters, mud filtration test data, relative permeability, and drilling time. With the accurately determined invasion radius, skin factor can be evaluated confidently. Then the well stimulation can be planned accordingly and appropriately, if it is necessary to remove or alleviate formation damage. Therefore, this work is significant in skin calculation and well stimulation design. It can also be used to estimate the cleanup period at the beginning of production, and allows engineers to predict the well performance and diagnose wellbore problems by checking any deviation from the predicted production. This study can also assist with the correction of parameters inferred from log measurements, thereby reducing the over and/or underestimation of log derived parameters used in various formation evaluation calculations.
Practical Laboratory Testing for Shale Fracturing
Authors: Fischer C. C. , Constien V. G. 
Published: June 2014

Abstract
A suite of practical laboratory tests has been developed to characterize the performance of shale fracturing fluids and chemicals. The testing suite includes friction reduction, capillary suction time, and shale strength changes after exposure to the fracturing fluid.
The friction testing method was correlated to previously published work in larger diameter tubing and utilizes a small volume of water so that actual field water samples can be used. The capillary suction utilizes off-the-shelf equipment to give rapid determination of fluid and shale interactions. The shale strength change method involves dynamic exposure of shale cores to the fracturing fluid at temperature, shear rates and times representative of the fracturing treatment. Shale strength changes are determined by measuring hardness of the core surface exposed to the fracturing fluid and comparing it to the opposite side of the core which was not exposed to fluids.
The friction reduction test has been used with great success to rate the performance of friction reducers in various types of water, to determine optimum friction reducer concentration, and to determine the interaction of other common additives such as biocides or scale inhibitors with the friction reducers. The strength testing has shown significant strength reduction in some shales with certain types of fracturing fluids and little strength reduction when the fracturing fluid was changed. A variety of fracturing fluids have been tested from slickwater to gelled oil fluids to traditional crosslinked fluid. The strength reduction should be indicative of proppant embedment in the shale.
The suite of tests proposed has been successfully used for multiple operators in order to determine interaction effects of fracturing fluids with shales as well as to optimize friction reducer performance.