bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Versatile Method for Evaluation of Antifoaming and Defoaming Agents in Oilfield Applications as a Tool for Green Product Development
Authors: Mahmoudkhani Amir , Wilson Bobby , Rocker Jacob 
Published: September 2011

Abstract
Foams are encountered in aqueous and nonaqueous systems throughout the upstream oil and gas industry from drilling and cementing to primary separation and production. Anti-foamers and defoamers are key ingredients to ensure efficient operations where uncontrolled foam causes problems. Application and performance of anti-foaming or defoaming agents are often assessed by blender tests or using sparge tubes. These tests, although simple and easily executable, are largely nonrepresentative of real-world conditions.
A versatile method, the FEAT (Foam and Air Entrainemnet Test), has been developed to better simulate the field behavior of oilfield antifoamers/defoamers in a laboratory setting. The FEAT is used to evaluate and optimize a variety of oilfield aqueous/nonaqueous systems which produce or encounter foaming conditions. Foam is generated by gas entrainment in the test media at a given temperature and pressure in the presence or absence of a foaming additive. The foamed media is then continuously recirculated while density and mass flow rates are measured and recorded to objectively quantify antifoamer/defoamer performance. The recirculating media may be altered, if desired, by successive dosage of salts, hydrocarbons or water over the time to better simulate field conditions and present a spectrum of medium behavior and additive performance. The dynamic nature of this measurement loop enables the evaluation of chemical additive systems under a variety of conditions such as brine buildup, water hardness, or hydrocarbon leaching. FEAT offers a versatile technique for developing new liquid and solid green products. Experimental results and field trials confirm the FEAT method better approximates field performance than commonly used tests. This allows for greater refinement of oilfield antifoamers and defoamers which offers both environmental and economical benefits.
Numerical Simulation of Mass-Transfer between Matrix and Fracture
Authors: Jamili A. 
Published: September 2011

Abstract
This paper presents a mathematical model and its numerical solution, describing mass-transfer between a gas flowing in a fracture and resident fluids in the adjacent matrix block. The model accounts for diffusion and convection mass-transfer mechanisms both for gas and liquid phases. Diffusion mass-transfer between the matrix and fracture is modeled by a mass-transfer coefficient while the convection mass-transfer is accounted for using Darcy equation and the appropriate flow potential gradients. The injected gas transported into the porous matrix causes vaporization of oil in the matrix pores, which, in turn, is transported by convection and diffusion to the gas flowing in the fracture. Compositions of equilibrium phases are computed using the Peng-Robinson equation of state.
The mathematical model was used to simulate a nitrogen injection experiment (Morel (1990)). The experiment was performed in a 1-D horizontal Chalk core for 16 days. All sides of the core were sealed except one side, where the injected nitrogen gas in the fracture flowed across that face. The initial resident fluids (oil and gas) in the core were a mixture of methane and pentane.
Calculated results matched the experimental data, including recovery of each component and gas saturation profiles inside the core. The simulation revealed the presence of countercurrent flow inside the core. Diffusion was the major contributor to the mass-transfer mechanism between fracture and matrix during the early times in the experiment while convection mass-transfer was more significant after 15 days. While these results are significant to prove the viability of the numerical modeling, extension of these results to field application depend highly on reservoir pressure, composition and many other factors. Nonetheless, this paper gives credence to mathematical modeling and provides a test case for researchers using other numerical techniques.
CT-Conveyed Sand Jetting Perforation on Deep, Tight Gas Well: Treatment Fluid Selection and Application Perspective
Authors: Fryzowicz R. , Maas T. 
Published: September 2011

Abstract
In the tight gas formations the perforation channel can be created by means of abrasive action. If possible to implement, such a method would leave clean cut hole in the liner without sharp edges and perforation tunnel in the formation free of crushed zone. The main advantage of sand jetting perforation lays in the cleaner and larger perforation channel. Perforations created with sand jetting technique usually display reduced near wellbore friction during hydraulic fracturing operations.
The preparations for sand jetting perforation operation in deep wells require proper selection of the carrier fluid. In deep horizontal wells sand laden slurry has to travel through small diameter coiled tubing increasing the injection pressure at the pump. In order to lower pump pressure at the required treatment flow rates the sand is suspended in highly pseudoplastic fluid. The sand suspension in large suction lines and friction reduction in smaller coiled tubing (CT) are the main parameters required to complete the operation. The selection of proper carrier fluid maintaining both parameters at the bottom hole temperature is crucial to the job success.
This paper will discuss the testing of fluid systems from the perspective of the sand suspension and friction reduction capabilities along with the discussion of basic properties and parameters of the selected system. The findings from the tests will be verified by the actual sand jetting perforation operation on the offshore deep tight gas well.
Field Test Results of an Innovative New Drilling Tool using Rate of Penetration Modulation
Authors: Farley Steven Reid , Maranuk Christopher A , Jasper Clint 
Published: September 2011

Abstract
Mud motors, in conjunction with a bent sub, have been used for over 40 years to directionally steer wells to a target location. Mud motor technology is well understood and has seen significant improvements over the years. Rotary steerable tool technology is relatively new to the oilfield and improvements are still being made to enhance performance and reliability. The significant advantage of rotary steerable tools is that the drillstring is continuously rotated throughout the drilling operation. A new system for wellbore directional control has been developed which uses continuous drillstring rotation above a positive displacement motor and bent sub. This new system offers many advantages of a rotary steerable system but also offers the proven technology of a positive displacement mud motor.
Steering is accomplished by managing pressure fluctuations within the drill string, creating slight oscillations in the flow rate through the mud motor. These controlled undulations in flow rate allow high frequency variations in drilling parameters to steer the well in any targeted azimuth. If the objective cannot be achieved using rate of penetration modulation in rotary mode, then the motor can still be oriented using the more conventional means of stopping rotating, sliding against the borehole until the motor is in its new orientation, and returning to rotating.
This paper will discuss the advantages and disadvantages of the new system compared to both conventional mud motor and rotary steerable technology. The paper will also discuss the early field trials of the new system in various hole sizes and discuss how selected parameters affect performance.
The Shale Gas Potential of China
Authors: Wang Xiuli , Wang TianJiao 
Published: September 2011

Abstract
China is energy hungry and shale gas, a recent engineering feat in the United States, is likely to prove an invaluable asset for China as well. Currently about 70% of China’s total energy is still from coal and only 4% derives from natural gas. Natural gas per capita in China is about 2.2 thousand cubic feet per year while, in the United States, it is about 77.4. To reach a semblance of a developed country’s energy profile, China has to increase its natural gas usage and this is an expressed policy of the government.
With growing international demand in natural gas, shale gas has become the brightest spot. It is an unconventional energy source, extracted from reservoirs with very low porosity (2% or less) and permeability (0.1 to 0.0001 md or even less). There are abundant reserves around the world, about 16,000 trillion cubic feet (Tcf). In China, shale gas resources are widely distributed in the Sichuan, Tarim, and Ordos basins and other continental sedimentary basins with shale gas formation conditions. The estimated potential shale gas resources in China amount to about 1,084 to 3,530 Tcf.
Despite this potential, China's shale gas exploration and development is still at its infancy.
This paper investigates the status of shale gas development in China and describes shale gas accumulations, their geographical distribution and the economic value of shale gas production to the country. If, emulating the United States experience, where in the course of less than ten years shale gas contribution to total gas production increased from essentially zero to 17% (estimated), Chinese shale gas could deliver 1.8 Tcf of gas (from a total projected gas consumption of 10.6 Tcf) with an annual value of preventable imports of about $18 billion by 2020.
A Practical Solution to Describe the Proved Area within a Resource Play Using Probabilistic Methods
Authors: Dobson M. L. , Lupardus P. D. , Divine T. W. , McLane M. A. 
Published: September 2011

Abstract
The United States Security and Exchange Commission (SEC 2008) adopted revisions to the oil and gas reporting disclosure rules on December 29, 2008 that included expanded definitions to allow entities to disclose reserves using probabilistic methods. These benchmark rule changes, titled Modernization of Oil and Gas Reporting; Final Rule are coincidently timed with the rapid discovery and development of world class resource play reservoirs. These resource plays are favorable subjects for probabilistic evaluation due to their shear size, well count, projected future activity and significant current and future reserve impact.
The modernized rules create new opportunities in reserve disclosure as well as new potential pitfalls. Probabilistic methods are not required to be implemented for reporting; however, if used they need to adhere to sound statistical principles to serve the purpose of the new rules and yield robust results. This paper presents a new approach that incorporates probabilistic principles into a practical method for the first step in reporting undeveloped reserves in a resource play; empirically describing the proved area.
The practical method presented here does not use a probabilistic approach previously shown by others (Patricelli, 1995), (Mata, 1997), (Moore 1999), (Acuna, 2000), (PRMS, 2009). Additionally it does not rely on Monte Carlo simulations for input values based on geologic variables expressed as Probability Distribution Functions (PDF). Instead, the method employs production statistics of the existing Proven Developed Producing (PDP) well set within the play.
The analog to future wells involves the existing PDP wells in the same geologic and geographic portion of the play being evaluated. Empirically the step that describes the proved area is controlled by statistical rules for sample size and the principle of aggregation. This approach is likely only applicable to resource plays. Other factors such as gas-in-place and reasonable recovery factors must also be considered to insure the results are reasonable.
The probabilistic reserve evaluation method requires a comprehensive level of support documentation. The objective of this paper is to present the principles and methods that create a robust, reliable, yet simplistic way to evaluate the proved area component of reserves evaluation using probabilistic methods for resource plays. Proved, probable, and possible reserves are allowed to be disclosed under the new SEC rules. However this paper is limited in scope to proved reserves. Explanations are provided to show how SEC definitions and probabilistic concepts are integrated into the proposed method. The Fayetteville Shale is used throughout the paper to demonstrate the application.
Stage Isolation Failure of Non-packer Reasons in Openhole Horizontal Completion
Authors: Zhou Desheng , Yuan Hong 
Published: September 2011

Abstract
Multistage fracturing in openhole horizontal completion is an economic technology in the production of low permeability reservoirs. Openhole horizontal completion requires sealing the surface of horizontal wellbore rock directly to create stages for fracturing. Packers are usually used to create the sealing stages. However, stage isolation failure is not uncommon during openhole fracturing. Packer is commonly blamed for the failure in the industry. The paper studies the other (non-packer) reasons of the isolation failure based on rock mechanics, fracturing theory, and finite element analysis.
The paper presents that stage isolation may be failure even for perfect packers. Four sources may yield the multistage isolation failures in addition to packer itself. They are wellbore wavy, wellbore diameter change, wellbore deformation to oval shape, and axial fracture and fracture initializing location.
To avoid the non-packer isolation failure, horizontal wellbore survey, stress and deformation around a openhole horizontal wellbore should be analyzed. Engineers may use the paper to improve multistage fracturing in openhole horizontal completion. It is also useful in packer selecting, setting, and designing for an openhole horizontal completion.
An Integrated Performance Model for Multilateral Wells Equipped with Inflow Control Valves
Authors: Zarea Marwan , Zhu Ding 
Published: September 2011

Abstract
Intelligent well technology is a relatively new technology that has been adopted by many operators in recent years to improve oil and gas production, and recovery. The technology uses downhole monitoring and control to regulate flow condition and provides solutions to production problems. It is one of the most effective means for optimization of commingled multilateral wells in heterogeneous reservoirs. Due to the high cost and complexity in intelligent multilateral well constructions, accurate modeling of the reservoir, completion and wellbore performance is essential to design an economically beneficial well, and the critical component, inflow control valves (ICV), should be integrated into the performance modeling process.
This paper presents an integrated analytical model that is built on existing models for predicting reservoir and wellbore flow behavior. Also, equations that can predict the flow performance through restrictions such as ICVs, in a multilateral well system are incorporated into the analytical model. The integrated model estimates the reservoir inflow and flowing wellbore pressure at each lateral of a multilateral well, then predicts the anticipated pressure drop across each ICV for any given flow rate. By knowing pressure and flow distribution in a well system, the flow rate distribution can be balanced by operating ICVs to achieve better flow conditions. This analytical model provides the engineers with a hands-on tool to select proper ICV positions for each lateral or segment and helps optimize the well production. Examples at field conditions are used in the paper to illustrate how the model can be used to improve well performance. Applications such as preventing crossflow in commingled multilateral wells are also presented in the paper.
A Practical, Application-Based Guide to Borehole Enlargement Tool Selection
Authors: McCarthy J.. , Rebellon J.. , Barton S.. , Rambhai R.. 
Published: September 2011

Abstract
With almost 45% of wells drilled globally employing some form of hole opening technology, borehole enlargement has become commonplace. However, for many reasons it can still be very demanding, from both planning and execution points of view, particularly in the deep water basins being exploited today.
To address the needs of these challenging applications, a variety of tools have been developed by many service companies. There are two primary borehole enlargement methods involving eccentric and concentric tools. Contained within these two general categories are many options: fixed cutter, roller cone, mechanical, hydraulic, hydro-mechanical, bi-center and so on. Factor in the different drive types available (rotary, positive displacement motor steerable, rotary steerable, coiled tubing) and the potential borehole enlargement options can quickly lead to a confusing, even circular, decision making process.
With so many options, an important question must be answered by the drilling engineer: How does one select the appropriate borehole enlargement option for a specific application? With continually increasing costs and more difficult wells being drilled around the world, there is little room for error. Several factors must be weighed and evaluated before making the correct decision. Depending on the type of well being drilled and the formation characteristics, one must choose the optimal BHA and drilling parameters to obtain a successful borehole enlargement result.
This paper reviews the decision making process that can lead to the best chance of success in many borehole enlargement applications. Understanding the application is critical in delivering a successful borehole enlargement operation. Based on results obtained over many years of industry experience with applications involving all types of borehole enlargement technologies available, a practical guide to hole opening solutions has been derived. It takes into account critical factors, including economics, borehole quality, equipment availability (including rig capacity), drive type, drilling parameters, the type of well being drilled, and formation characteristics.
After a brief introduction and a description of currently available technologies, this paper will review the decisions that are made in determining which borehole enlargement tool to use and how to apply these in practice. This allows the drilling engineer to have a practical view of the available options and their versatility for proper tool selection.
Comprehensive Energy Price Model Including Deepwater Drilling Risk
Authors: Belhaj Hadi , Lay Terry , Lau Richard , Lau Laura , Rahuma Khulud 
Published: September 2011

Abstract
Relying solely on traditional drilling technology to estimate the world’s proven Oil Reserves denies the likelihood that billions of barrels of unfound oil lay just outside the industry’s technological reach. With substantial financial and legal assistance and government support to develop newer technologies like Deep-Water Drilling (DWD), the major oil companies and the US White House are confident that new fields can be brought into production that should increase supplies and stabilize or lower energy prices. Each new find, they estimate, will help increase the world’s proven oil reserves allowing investors and consumers to feel more optimistic about providing for their future energy needs. It is also hoped that this new technology will lead to safer, more economic and environmentally appealing exploration and production methods (Belhaj, et al)1.
Pertinent questions arise as to what impact BP’s tragic oil spill may have on the future of Deep-Water Drilling and on the future of energy prices? Does industry have the technology to successfully and economically exploit fields using DWD? What role should governments play in regulating dangerous, environmentally unsound drilling practices? Should regulations be allowed to impede progress?
Identifying DWD as having a major influence on cost and being a critical parameter in any energy equation, the authors answer these questions and present two models that pessimistically and realistically describe the future role of DWD in places like China, India and Brazil over the next 50 years – places with growing populations and economies, but little government oversight.
Conclusions are reached with a discussion about the need for DWD in the current economic slowdown in advanced economies that have witnessed decreased oil demand and why traditional models affecting energy prices have been unsuccessful in predicting the current high energy prices.
Low-Rate Fracture Treatment in the Bakken Shale Using State-of-the-Art Hybrid Coiled-Tubing System
Authors: McNeil Fraser , Harbolt William , Bivens Eric , Lindsay Sharlene , Paterniti Melanie 
Published: September 2011

Abstract
In low-permeability formations, natural fractures, fissures, and other geologic heterogeneities are important considerations in the design of hydraulic-fracture treatments. In some formations, it is considered beneficial to capitalize on these conduits to establish a greater network of connection to the reservoir. In the Bakken shale, near Westby, Montana, a simple planar fracture was desired because complex fracture growth could result in connectivity to a zone of nonproductive interest and led to the following issues:
Higher rates, which could result in extreme fracture complexity and limited fracture extension. Inability to effectively place proppant for conductivity. Excessive fluid leakoff caused by high net pressures requiring large pad volumes. Connection to water-producing zone. Less aggressive proppant schedule because of likelihood of screenout. Increased cost, footprint, personnel, and equipment on location.
With an understanding of the formation-rock properties, stresses, and the natural fracture system, the treatment design parameters were established to help ensure lower treatment pressures and optimum fracture extension in the zone of interest. This paper presents the successful execution of a multi-interval fracture-stimulation treatment for a long-lateral horizontal completion in the Bakken shale using a state-of-the-art hybrid coiled-tubing (CT) system and hydrajet-assisted fracturing (HJAF) technology. The new approach incorporated the following technology:
Low-rate treatment schedule. Multiple-fracture stimulation treatment. Aggressive proppant-treatment schedule. Higher gel viscosity to encourage desired fracture growth and proppant transport. Hydrajet perforating. Dynamic fluid diversion to isolate treatment to intended zone. State-of-the-art hybrid CT system.
Water Injection Enhancement through a Novel Oil-Soluble/Water-Dispersible Combination Cleaner and Corrosion Inhibitor
Authors: Hilfiger M. G. , Stewart S. A. , Ansari A. M. 
Published: September 2011

Abstract
A novel oil-soluble/water-dispersible combination cleaner and corrosion inhibitor was developed. It is designed to be applied in water injection lines to clean deposits, inhibit the formation of future deposits and provide protection from corrosion. This chemistry is especially effective against paraffinic/hydrocarbon deposits, which can help hold together scale such as iron sulfides and help them adhere to the pipe walls, filters, and increase downhole plugging. Evaluation of deposits from various field locations in North America was performed via bottle shaking dispersion studies. The amount of hydrocarbon uptake into the water phase was measured through the use of fluorimetry. Our testing clearly reveals the ability of the product to break down these deposits over time and prevent re-adhesion onto pipe walls. To study the effect of this material on the near wellbore area in the injection wells, core flood studies were performed that indicated no formation damage occurs, and that the material can readily clean the near wellbore. Corrosion testing was performed using kettle test protocols in synthetic brine and also with oxygen sparging. In all cases, the product was able to provide excellent cleaning capabilities and corrosion inhibition, even in the presence of oxygen.