bluuebunny/crossref_metadata_2025_split huggingface dataset:
Nanotechnology Applications in Viscoelastic-Surfactant Stimulation Fluids
Authors: Huang Tianping , Crews James B. 
Published: December 2007

Abstract
Viscoelastic surfactant (VES) fluids have been widely used in the oil industry as completion and stimulation fluids. The surfactants structurally arrange to form rod-like micelles that increase VES fluid viscosity for regular fracturing and frac-packing fluids. However, high fluid leak-off and low viscosities at elevated temperatures have limited VES fluids for hydraulic fracturing and frac-packing applications.
This paper will introduce a nanotechnology application for maintaining viscosity at high temperatures and controlling the fluid loss of VES fluid, without generating formation damage. The nanometer-scale particles studied display unusual surface morphologies and have high surface reactivity. These nanometer-scale particles, through chemisorption and surface charge attraction, associate with VES micelles to: 1) stabilize fluid viscosity at high temperatures; and 2) produce a pseudo-filtercake of viscous VES fluid that significantly reduces the rate of fluid loss and improves fluid efficiency. When internal breakers are used to break the VES micelles, the fluid will dramatically lose its viscosity and the pseudo-filtercake will then break into nanometer-sized particles. Since the particles are small enough to pass through the pore throat of producing formations, they will be flowed back with the producing fluids, and no damage will be generated. The results of rheology, leak-off and core flow tests will be presented for the VES fluid systems at temperatures 150°F and 250°F.
Decision-Making Process in Development of Offshore Petroleum Fields
Authors: Deguchi Hayashi Suzana H. , Ligero Eliana L. , Schiozer Denis J. 
Published: December 2007

Abstract
Risk is inherent to all phases of a petroleum field lifetime due to geological, economic and technological uncertainties, which are very significant on oil recovery in development phase, the focus of this work. The acquisition of additional information of uncertain attributes and flexibility during the development are key points to risk mitigation. The Value of Information (VoI) is used to quantify the benefits of new information, giving more accuracy to the project. The Value of Flexibility (VoF) measures the benefits of adding flexibility to the project considering different possible scenarios.
A new and reliable methodology has been proposed to quantify VoI and VoF based on the decision tree technique in order to combine the uncertain attributes. All reservoir models generated by the tree are submitted to parallel simulation and Geological Representative Models (GRM) are selected to represent geological uncertainties. The methodology includes the criteria used for selection of GRM, optimization of production strategies of each GRM considering the gathering of additional information and statistical treatment of the results.
The methodology has been applied in a decision-making process of a giant offshore petroleum field. The field has been developed by blocks due to its physical limitations and intrinsic characteristics and the high investment necessary to develop a giant field.
The contributions of this work are (1) to show the importance of VoI and VoF concepts in decision-making process in petroleum field development and the complexity of this type of decision, (2) to apply the proposed methodology in a giant offshore field modeled by parts, minimizing risks associated to the development of this type of field and (3) to evaluate the importance of the reservoir uncertainties in risk mitigation. An additional important contribution is to present the details of the use of reservoir simulation in the process, trying to obtain the best relationship between computation effort and reliability of the decision making process.
Optimising Diversion and Pumping Rate To Effectively Stimulate Long Horizontal Carbonate Gas Wells
Authors: Liang Jin , Wong Paul , Sinanan Brent 
Published: December 2007

Abstract
Malaysia is a significant gas producer and LNG exporter within Asia-Pacific region. Many of the country's gas fields are offshore carbonate reservoirs. The exploitation of these reserves involves drilling horizontal wells for maximizing reservoir contact and hydrocarbon drainage. Many of these wells experience drilling mud damage. One of the challenges in stimulating long horizontal wells with open-hole completion is the placement of stimulation fluids for effective zonal coverage and generating wormholes to pass the damaged zone.
Placing gelled acid through coiled tubing has been the standard practice to clean up the wellbore. Due to the low pumping rate, stimulation results have been limited. A change was initiated aiming to have the acid pass the damaged zone and generate wormholes through effective diversions.
This paper describes the application of acid/diversion systems and pumping schedules to improve acid coverage. The selection of in-situ crosslinked and particulate diverters through laboratory testing is described as well as the implementation of a unique mixing system. Several case histories are presented illustrating the effectiveness of the fluid systems and mixing process in improving well productivity and job economics.
A stimulation campaign was executed in 2006 to utilize the systems selected in long open-hole horizontal carbonate gas wells. To maximize the results, the following have been practiced: Clean up and test the wells after completion to get initial productivity.Bullheading acid to increase pumping rate.Use a mixing-on-the-fly unit in limited barge space.Learn from previous jobs to improve subsequent ones by optimising pumping procedures.Clean up and flow test right after stimulation to evaluate results.
7 wells were stimulated in the campaign. Significant gain has been achieved through progressively optimising pumping procedures. Indication of diversion was observed compared to previous practices. Stimulation cost is less than that of using coiled tubing.
The Application of Specifically Formulated Bridging Materials To Successfully Reduce Pore Pressure Transmission To Enable Depleted Fractured Reservoirs To Be Drilled and Produced Without Incurring Formation Damage
Authors: Vickers Stephen , Cowie Martin , Burgess Mick , Anderson David 
Published: December 2007

Abstract
There is an increased demand for the design and application of non-damaging fluids in reservoirs that are depleted and susceptible to deep invasion of damaging mud solids. To enable a reservoir drilling fluid to function correctly, it is necessary to very rapidly deposit an external filter cake and reduce filtrate loss to a minimum. The cake must be backflowed in the production phase with minimum liftoff pressure and leave little or no permeability reduction. To achieve this, an accurate description of the pore throats in the reservoir is required. If this cannot be obtained, or the reservoir is at risk to fracture, then another approach is required.
This paper illustrates the methodology of utilizing a variable calcium carbonate bridging distribution mixed with powdered graphite which overcomes the problems of drilling reservoirs with varying pore throats and fractures. The bridging materials will enable an efficient control of filter cake deposition, and also allow for easy disruption of the cake integrity, when the well is back flowed in the production phase.
Results proving the effectiveness of this approach can be shown from return permeametry work in the laboratory, and successful field trials of its application in the Southern North Sea and the Middle East.
The use of these non-damaging products, and the engineered size distribution, will greatly decrease the difficulty at which fractured and depleted reservoirs can be drilled and will not reduce the productivity of these wells, that have in the past experienced formation damage due to deep fluid and solid invasion.
Thermophilic Enzymes for Filtercake Removal at High Temperature
Authors: Cobianco S. , Albonico P. , Battistel E. , Bianchi D. , Fornaroli M. 
Published: December 2007

Abstract
Since developments in the biotechnological field contribute to the implementation of new enzyme breakers for removing polymer damage, significant improvements in well productivity have been proved mostly in horizontal and multilateral wells. Indeed, a delayed clean-up treatment is often required for removing the filtercake after drilling when the drawdown of the well is not enough. Conventional acid treatments promote a rapid, localized reaction resulting in a partial, non-uniform removal of the mud cake. Additionally more and more restrictive regulations push to find less corrosive and more environmentally safe clean-up options including low toxic oxidizing agents and enzyme breakers. Historically, the enzyme's applications have been limited to low temperature treatments due to their pH, salts and temperature concerns. Recently, new temperature-stable, polymer specific enzymes have been isolated and investigated for degrading the polysaccharides (starches and viscosifying agents) commonly used in the Drill-in Fluids.
This paper describes the laboratory evaluations performed on three new enzymes with the aim to develop a non-corrosive clean-up treatment specifically designed for degrading starches, xanthan gum and scleroglucan at temperatures reaching 100°C. Static break tests showed that these polymer-specific enzymes aggressively attack the polysaccharide backbone resulting in a complete break of the polymer. Nevertheless the treatment fluid do not have an immediate reactivity, which might ensure a uniform distribution of the fluid across long pay sections with minimal leak off during placement. Degradation is very effective and the generated fragments are small, soluble molecules. Besides the temperature and pH dependence, the influence of different heavy brines (CaCl2, CaBr2, etc.) on the enzyme activity and salting-out effect were also investigated. The optimal application concentration range for each brine was identified. By coreflooding tests the effectiveness of these breakers in removing the filtercake has been confirmed and the non-damaging properties of the degraded fragments assessed.
The Effects of Acid Contact Time and the Resulting Weakening of the Rock Surfaces on Acid-Fracture Conductivity
Authors: Melendez M. G. , Pournik M. , Zhu D. , Hill A. D. 
Published: December 2007

Abstract
Acid fracturing is a stimulation process in which lasting conductivity after fracture closure is created by uneven etching of the fracture face. The success of an acid fracturing treatment depends on the conductivity created being retained under overburden stress. Fracture conductivity is usually predicted using correlations based on limited tests conducted at low injection rates that may misrepresent hydrodynamic effects that occur in the fracture. We have conducted a new series of acid fracture conductivity experiments at conditions more representative of field conditions to explore the correlation between the experimental conditions and the rock properties with the final conductivity.
In order to reproduce field conditions in the lab, we have used a lab set up properly scaled through matching of dimensionless numbers. Tests were conducted with Indiana limestone, San Andres dolomite, and Texas Cream chalk. A gelled acid system was used with varying contact times. The etched fracture surface was characterized and the rock embedment strength was measured before and after acidizing in addition to standard conductivity measurements for each experiment.
In this paper, the results from a systematic experimental study are presented. Experimental results illustrate that the fracture surface etching pattern is a dominant factor for fracture conductivity. If channels are created, the fracture will have retaining conductivity after closure. Rock strength is another important parameter in acid fracturing. Formations with low initial Rock Embedment Strength (RES) values or a lager reduction in RES after acid injection have lower conductivity after closure. Measurements and analyses of rock embedment strength provide understanding of the conductivity behavior in acid fracturing.
The results of preliminary tests for a North Sea chalk are also presented and discussed in the paper.
Real-Time Fluid Distribution Determination in Matrix Treatments using DTS
Authors: Glasbergen Gerard , Gualtieri Dan , Van Domelen Mary Susan , Sierra Jose 
Published: December 2007

Abstract
In matrix treatments, placement of the injected fluids is essential for success. Over the years, several diversion and placement techniques have been applied to obtain a desired fluid distribution. Real-time evaluation of a treatment was limited to observing injection pressures or bottomhole pressures. These measured pressures provided some information on the diversion process. The application of distributed temperature sensing (DTS) during matrix treatments to monitor the temperature profiles along the wellbore in real time is a recent method to obtain a qualitative indication of the fluid distribution. In this paper, we will discuss whether DTS can also be used to quantify the fluid distribution during a matrix treatment.
For the real-time quantification of the fluid distribution during a matrix treatment from temperature surveys, both real-time read outs of the temperature surveys and an accurate real-time model are needed. With DTS, the real-time read out is a feasible technique that has been developed to present and evaluate the temperature surveys in real time. Further, a coupled wellbore and near-wellbore thermal model is available that runs in real time. This paper will describe these techniques and models and validations using several case histories.
In addition, an analysis of matrix treatments using DTS temperature surveys, where available, will be presented. The models will be used in the analysis to obtain calculated fluid flow distribution. We will discuss how this methodology can be applied in real time and what benefits quantification of fluid flow distribution offers. Further, we will describe what other benefits can be obtained from real-time temperature profiles during stimulation treatments.
An Acid-Placement Model for Long Horizontal Wells in Carbonate Reservoirs
Authors: Mishra Varun , Zhu D. , Hill A. D. , Furui K. 
Published: December 2007

Abstract
In several places around the world, notably the North Sea and the Middle East, carbonate reservoirs are being accessed with very long horizontal wells (2000 to 20,000 feet of reservoir section.) These wells are often acid stimulated to remove drilling fluid filter cakes and to overcome formation damage effects, or to create acid fractures or deep matrix stimulation to enhance productivity. Good acid coverage with a relatively small acid volume is required to economically obtain the desired broad reservoir access.
We have developed a model to predict the placement of injected acid in a long horizontal well, and to predict the subsequent effect of the acid in creating wormholes, overcoming damage effects, and stimulating productivity. The model tracks the interface between the acid and the completion fluid in the wellbore, models transient flow in the reservoir during acid injection, considers frictional effects in the tubulars, and predicts the depth of penetration of acid as a function of the acid volume and injection rate at all locations along the completion.
We have used this model to simulate treatments that are typical of those performed in the North Sea and in the Middle East. We present a hypothetical example of acid placement in a long horizontal section and an example of using the model to history match actual treatment data from a North Sea chalk well.
Optimized Perforation Tunnel Geometry, Density and Orientation to Control Sand Production
Authors: Zhang J. , Standifird W. B. , Shen X. 
Published: December 2007

Abstract
Destabilization of completed sandstone reservoirs reduces production rates and degrades production equipment. A major cause of such destabilization is perforation tunnel failure, which causes sand production.
Classic mechanically-based sand control techniques are effective, but potentially unnecessary for some reservoirs. Modeling the occurrence and severity of sand production should help identify the most economical pairing of sand control remediation methods with the desired production rate.
This paper examines an advanced technique for modeling such failures, leading to improved drilling and completion practices. In this study, 3D poro-elastoplastic Finite Element Methods (FEMs) are employed to model perforation tunnel stability. Wellbore geometry, reservoir properties, draw-down rate and perforation properties such as tunnel size, spacing and orientation are addressed, with particular attention focused on the transient phenomena near perforations, including stress redistribution and failure development for different perforations.
The results show that stability of the wellbore and perforation tunnel strongly depends upon drilling and perforation directions and perforation shot density. The relationships of the bottomhole flowing pressure, drawdown, perforation orientation, rock strength and in-situ stresses are given to provide optimal perforation for mitigating sand production.
Recent Advances in Deepwater Horizontal Injector Wells Acidizing in Campos Basin
Authors: Pereira Alexandre Z.I. , Calderon Agostinho , Chagas Carlos M. , Pinto Edilson A. 
Published: December 2007

Abstract
In most of its deepwater Campos Basin oilfields, Petrobras' strategy has been to develop the waterflooding systems by using open hole horizontal gravel packing. Both, perforation and gravel packing operations, are only possible by the presence of the filtercake, formed on the formation face during the drilling process. Nevertheless, that film becomes an impediment to injection and must be removed to obtain good injectivity.
Despite the development of special tools that permit to acidize just after the gravel packing operation, there was still a need for reducing the operation time and to increase the damage removal efficiency.
With this purpose, changes were made in the diverting systems to allow each acidizing stage to treat larger intervals, thus reducing the treatment's total number of stages. This improvement was possible by modeling the fluid flow through the tool's perforated extension, which saved 30% of the pumping time.
Parallel to this development, acidizing historical data were revised and filtercake invasion studies were performed. The conclusion was that more aggressive acidizing formulations could be used, what reduced the pumping volume and reduced the job time even further, to about 50% of the previous times.
Post job formation tests performed have shown that not only a job time reduction was achieved, but also, a better formation damage removal.
The good effects observed have resulted in a general review in the design of the horizontal injectors acidizing jobs, improving the operation's safety, efficiency and effectiveness.
This paper will describe the technique, job details and the results obtained for these particular operations.
Formation-Damage Observations on Oil-Based-Fluid Systems Weighted with Treated Micronized Barite
Authors: Kågeson-Loe Nils , Watson Russell , Prebensen Ole Iacob , Van Der Zwaag Claas , Taugbøl Knut 
Published: December 2007

Abstract
A unique oil-based drilling fluid system weighted with treated micronized barite (TMB) slurries has been developed and successfully introduced to the field. The utilization of this weight material provides the fluid system with low viscosity, reduced torque values, superior sag stability thus giving a fluid with low Equivalent Circulating Density (ECD) contribution and excellent hydraulics performance. These exceptional fluid characteristics make the fluid system an excellent solution for drilling sections with narrow mud-weight windows, coiled tubing operations, managed pressure drilling and extended reach drilling. Many of these drilling challenges are encountered in high-temperature, high-pressure (HTHP) and ultra-deepwater field developments and in depleted, mature fields.
Much of the early fluid system development focused on design, the system's physics and chemistry, and the optimization of mineralogy of the weighting agent. Also of concern was the variability of results seen both from return permeability as well as from standard fluid-loss experiments. On this basis a comprehensive study was undertaken to identify and understand the damage mechanisms operating in the formation and filter cake. During this period the fluid system was used in a number of operations in the North Sea such that the current available database includes 5 different types of field applications.
The paper presents the findings of the formation damage study including relevant productivity data from the various field applications. The results demonstrate that while invasion of the formation by treated micronized barite can occur, it does not necessarily lead to permanent productivity impairment. Furthermore, the micronized barite does not interfere with the added fluid-loss-control material over a wide range of fluid densities and formation permeabilities. The authors discuss the processes observed relating them to current field experience describing why the formation damage mechanisms do not concur with previous preconceptions and moreover describes where the limitations of the system occur.
Driving Completion Technology in Subsea, Multilateral Well with Sand Control and Downhole Flow Control
Authors: Wilson Allan , Allam Robbie , Horne Ken , Ballard Tracey 
Published: December 2007

Abstract
This paper presents a significant case study on the completion of BP's first Subsea, multilateral well incorporating both expandable sand screens and downhole flow-control. Discussed in the paper are the project drivers, completion design philosophy and challenges faced by the multi-disciplinary team throughout the planning and execution of this highly complex well. The paper will also present the operational issues and improvement opportunities identified and finally discuss the potential future applications for these technologies in this and other BP fields.
The Schiehallion field is situated on the Atlantic margin of the United Kingdom Continental Shelf (UKCS) some 175 km west of the Shetland islands in water depths of between 350 and 450 m. Schiehallion FP02 was planned as a multilateral well in order to maximize the reserves delivery from the North West Area Development of the field and also provide significant cost savings over the alternative two well options. In order to fully realize the benefit of the multilateral well option, down-hole flow-control (DHFC) was also required to optimize reservoir management and reserves recovery by independent control of the two individual well-bores. Sand control was provided by expandable screens.
Schiehallion well FP02 was successfully completed in July 2006. All of the main objectives were achieved and the well delivered both ahead of schedule and under budget. Incorporating DHFC in conjunction with open-hole sand-control introduced a number of industry and BP technology "firsts" throughout the well construction process. The successful introduction of these various technologies is attributed to rigorous planning and meticulous attention to detail.
The success of FP02 has been a major milestone in the business unit technology plan, demonstrating that combining these technologies is a viable option in this environment. As infill drilling targets become smaller, this technology has the potential to reduce development costs and therefore extend field life.