bluuebunny/crossref_metadata_2025_split huggingface dataset:
Successful Hybrid Slickwater Fracture Design Evolution—An East Texas Cotton Valley Taylor Case History
Authors: Handren Patrick , Palisch Terry 
Published: December 2007

Abstract
As the development of tight/unconventional and partially depleted gas reservoirs has increased, so has the demand for more innovative hydraulic fracture designs. Operators are increasingly placing proppant with slickwater, linear gel or hybrid fracture designs. While the benefits of these designs are typically attributed to a reduction in gel damage of the proppant pack, many operators mistakenly believe that the resulting fractures are not conductivity-limited.
Since few (if any) models on the market can adequately model the propagation of a slickwater frac as well as the associated proppant transport and deposition, it becomes difficult to optimize these fracture designs. This has led many operators to incorrectly assume that only small diameter sand or resin-coated sand may be placed in these types of designs, and that these products supply ample flow capacity.
However, one East Texas operator has combined insight into proppant transport with an appropriate understanding of realistic proppant pack conductivity to develop a novel, hybrid slickwater fracture design. This design has allowed the placement of larger diameter, higher conductivity proppant in fractures that many believed could not be placed either operationally or economically. Additionally, this operator has developed a unique pumping strategy to place the highest conductivity proppant in portions of the fracture where it provides the most value.
This paper will present a case history of these new hybrid slickwater fracture designs in this operator's East Texas, Cotton Valley – Taylor completions. The design theory and sequential improvements will be documented, including larger diameter, higher strength proppants, as well as a novel placement design. Field results from the first six wells fractured will be presented, showing substantial increases in gas production compared to similar offset completions. Economics will also be shown to illustrate the tremendous value added to completions utilizing this hybrid fracture design.
Computational Fluid Dynamics (CFD) Erosion Study for Chokes
Authors: Peri S. , Rogers B. 
Published: December 2007

Abstract
Because erosion is a common cause of failure in oilfield equipment, it is beneficial to approach the issue at the product design level. The areas most susceptible to erosion occur near changes in flow direction because here the particles are most likely to deviate from the flow stream and impinge on the surface geometry. While both experimentation and computer simulation are used to study erosion, experimental testing often proves difficult to perform for specific conditions. Computational fluid dynamics (CFD) simulations are used to predict erosion rates, with flow modeling and particle tracking being key tools for predicting erosion.
This paper presents a set of curves to estimate erosion of different components of the choke as a function of choke position and flow rate using CFD. Erosion results are plotted in terms of thickness loss per time in units of mils/yr as provided for each component for varying flow rates and sand volume concentrations. Results from the study show that the erosion rates increase in a quadratic fashion with respect to the flow rate. The predicted erosion rates for various scenarios are examined and compared to experimental results.
Optimizing the Production System Using Real-Time Measurements: A Piece of the Digital Oilfield Puzzle
Authors: Thompson Robert B. , Shanmugam Valli , Sinha Shekhar , Collins Natalie , Bodwadkar Suhas , Pearcy Marc , Herl Stan 
Published: December 2007

AbstractThe oil industry is investing millions of dollars in the infrastructure of digital oilfields in an effort to increase efficiency and recovery. An important part of the puzzle, transferring data from the wellsite to the office in real-time, is very much solved. However, this data is largely used to monitor the status of wells and equipment, and in most cases, the life cycle of the data ends there. A key part of the puzzle is to utilize the real-time data to optimize the production system, from the wellbore to the reservoir where most of the value lies. With the current infrastructure and technology we can get real-time data up to every second. The challenge is to extract the right information from that data at the right time to impact the way fields are managed.This paper discusses the workflows utilized in identifying production optimization and enhancement opportunities from large amounts of streaming data flowing from a number of wells. Case studies are presented for mature waterfloods in four different fields with over 60 wells. The economic impact of surveillance is quantified through electrical costs, efficiency in fluid movement, and enhanced reservoir deliverability. The real-time data analysis for the entire field revealed opportunities to increase the production in the short-term, as well as the necessity to adjust the long-term exploitation strategy.The methods and examples in this paper show the value of applying digital oilfield technologies in one of the most cost sensitive environments in our industry. Observations based on a large number of wells during a 2-year period show that over 50% of the wells can benefit from some form of optimization, resulting in a substantial increase in production.
The Effect of Weighting Material Sag on Drilling Operation Efficiency
Authors: Omland T. H. , Saasen A. , Zwaag C. V. D. , Amundsen P. A. 
Published: December 2007

Abstract
Drilling in subsurface formations requires control of down-hole pressures. Weighting materials are typically added to the drilling fluid and provide, ideally, a homogeneous fluid column with an even density to control these pressures. However, experience has shown that keeping the weighting material in suspension can be challenging. Especially when drilling with synthetic or oil-based drilling fluids the nature of the fluids prevents the generation of sufficient gel structures to keep high density particles in suspension. On one offshore operation the rig had to be evacuated. Because barite was sagging out of the drilling fluid and left a residual fluid phase with too low density, gas was entering the well during drilling.
This paper provides a review of the sag studies performed to date, describes various testing techniques for sag evaluation as well as giving description several field cases where weighting material sag occurred. It also shows how the efficiency of operations was affected. The cases are analyzed and suggestions are made concerning the operational elements that may have provoked the incidents. The analyses use time-based drilling data to provide detailed information of the operational sequences prior to the sag incidents and how the incident was handled at the site.
Several previous studies have shown no correlation between weighting material sag and standard measurements of drilling fluid properties. The present study, however, focuses on other fluid properties essential to hinder weighting material sag.
Contacting More of the Barnett Shale through an Integration of Real-Time Microseismic Monitoring, Petrophysics and Hydraulic Fracture Design
Authors: Daniels J. , Waters G. , LeCalvez J. , Lassek J. , Bentley D. 
Published: December 2007

Abstract
Horizontal wells represent a growing percentage of the rig count in unconventional gas wells in the United States. With effective stimulation techniques they have been shown to have favorable economics compared to vertical wells in the same reservoir. This is because of the large hydraulic fracture surface area that can be created from horizontal wells if effective stimulation techniques are employed. The Barnett Shale formation is the reservoir that has seen the largest growth using this technique in recent years.
Estimated to extend over 54,000 square miles, the Barnett Shale formation displays different reservoir characteristics and properties in its different regions. The heterogeneous nature of this unconventional play makes standardization of the completion process problematic. One technology that has been used with increasing regularity to understand complex fracture geometry is microseismic (MS) fracture mapping1. Recent technology advances have made it possible for an onsite computer to process the thousands of seismic traces and deliver MS events hypocentral locations in a matter of seconds to a viewer in the fracturing treatment vehicle. Microseismic mapping used in conjunction with wellbore images and sonic logs has shed considerable light on the challenges faced in this reservoir.
Massive water fracs are currently used to create complex hydraulic fracture networks. This stimulation technique, while successful, often leaves behind unstimulated sections of the reservoir. In order to achieve optimum horizontal well stimulation the lateral section must be characterized so that geologically different intervals can be identified and the proper stimulation technique employed. Technology has progressed to the point that microseismic monitoring of hydraulic fracture stimulation can efficiently provide extensive diagnostic information on fracture development and geometry in real-time.
The case studies in this paper show how the use of real-time fracture mapping allows for on-the-fly changes in fracture design. Mapping also impacts the perforation strategy and restimulation designs to maximize the Effective Stimulation Volume (ESV). ESV is defined as the reservoir volume that has been effectively contacted by the stimulation treatment as determined by microseismic event locations and density. This paper further correlates MS activity to log data and illustrates how logs can be used to estimate fracture geometry. This data is then used to design a fit-for-purpose stimulation that has the greatest chance of maximizing the ESV and production.
Improving the Value of Real-Time Drilling Data to Aid Collaboration, Drilling Optimization, and Decision Making
Authors: McLaren G. , Hayes M. J. S. , Brown N. M. , Okafor Z. , Megat I. 
Published: December 2007

Abstract
Evolution in the manner in which real-time data is provided by service companies in the drilling industry has led to real-time data being available via the Internet from most wells drilled worldwide. The platform for viewing this real-time data is usually through a variety of viewers embedded in Web server software. By using technologies to enable the clear presentation of this Web-based data in real time to the end user—including data visualization, model comparison, and rig time usage—it is possible to improve real-time collaboration and perform drilling optimization actions from both a location remote to the wellsite (e.g., the operator's office or even a service company office) and the wellsite itself. By looking at three case studies in two locations (the North Sea and the Gulf of Mexico), it is possible to show how technologies that enable collaboration between onshore and offshore personnel and manage drilling risks not only improve operations monitoring and reporting but reduce drilling process time.
The three case studies demonstrate aid which eliminated an intermediate liner string; improved real-time understanding of well conditions by managing hole cleaning and drilling risks, ensured that a casing string could be successfully landed on bottom; and enabled cause-and-effect analysis of drilling events in real time in addition to post event analysis for improved evaluation of the drilling process. In all these cases, the use of enabling technologies within one integrated application brings advantages to the drilling process through the clear presentation of real-time drilling data, which allows easier interpretation of real-time drilling measurements.
Pressure-Wave Propagation Technique for Blockage Detection in Subsea Flowlines
Authors: Chen Xianghui , Tsang Ying , Zhang Hong-Quan , Chen Tom X. 
Published: December 2007

Abstract
Solids blockage due to wax deposition and/or hydrate formation in subsea flowlines is one of the major risks for deepwater production systems. Blockage causes high pressure drop and even stop of oil and gas production. The ability to determine the location, length and severity of blockages allows operators to select cost-effective mitigation or remediation strategies and execute the corresponding mitigation or remediation procedures efficiently Due to the difficulty to access subsea flowlines, a remote technique to detect the blockages is highly desirable. This study investigated the feasibility of using the pressure-wave propagation technique to detect blockage in subsea flowlines.
Pressure waves are generated when the production stream is released for a very short period of time at the flowline outlet on the host facility (either a fixed platform or a floating platform). The pressure waves propagate through the flowlines at the local sonic speed and are reflected to the flowline outlet after encountering a blockage. The time and amplitude of the reflected pressure wave from the blockage are quantitatively related to the characteristics of the blockage. This transient method was examined numerically and experimentally in the present study. Results indicate that pressure-wave propagation technique is a remote, non-intrusive and cost efficient method that can be applied to detect blockages in gas transport pipelines and subsea wet gas multiphase flowlines with gas as the continuous phase.
Beyond Money, What Is Important to Petroleum Professionals?
Authors: Collarini Cheryl R. , Sibille Amanda B. 
Published: December 2007

Abstract
A recent survey of petroleum industry professionals, including many engineers, was conducted by Collarini Energy Staffing Inc. to determine what non-monetary factors are most important to them. The respondents were asked to accept that they are fairly compensated, then asked to rank 36 factors in three categories: the position, the company environment, and the impact of the position and company on the employee's personal life. The respondents also were requested to rank those factors in two ways: how important each issue is to them and how well their current company meets their needs related to that issue. Over 10,000 professionals were asked to participate. The identities of the respondents were not recorded in order to provide complete anonymity. The response was significant. Beyond compensation, and in a highly competitive market for excellent people, other factors become important. The results of the survey were consistent across gender and occupation, with only minor fluctuations. Challenging work and corporate reputation were ranked of primary importance. Ranked second, but numerically very close, were all factors that relate to the people and the culture of the organization.
Theory and Application of Probabilistic Method of Designing Customized Interval Control Valves Choke Trim for Multizone Intelligent Well Systems
Authors: Ajayi Arashi , Konopczynski Michael 
Published: December 2007

Abstract
This paper describes a stochastic approach to the design of interval control valve choke trims for an intelligent well system. The paper builds on the deterministic approach of specifying the Cv characteristics of a multi-position control valve. The probabilistic method considers reservoir uncertainties in productivity indices, zonal pressure drawdown, expected production (or injection) rates and field production operation philosophy.
This design approach allows the control valve to meet the expected control objectives and ensures that the design trim is applicable to a wide range of well performance. The probabilistic method is demonstrated using real data from field examples.
The probabilistic design methods described in this paper are applicable to all intelligent well systems using variable choking valves, on both production wells and injection wells. The methodology is also applicable to intelligent well systems targeting reservoirs with characteristics that are widely uncertain. This method will enable the engineers to design an interval control valve (ICV) that incorporates reservoir uncertainties with field control philosophy leading to an optimized well delivery system.
On the Influence of Viscosity Upon ESP Performance
Authors: Amaral Gilmar , Estevam Valdir , Franca Fernando A. 
Published: December 2007

Abstract
This paper presents experimental data and a preliminary analysis on the operation of centrifugal pumps with viscous liquids. Two centrifugal pumps, a conventional radial (Ns = 1000) and a semi-axial electrical submersible pump - ESP (Ns= 3850) were instrumented and tested with water – 1 cP, and clear glycerin. The glycerin viscosity was varied from 67 cP to 1020 cP, through changes in temperature, encompassing the viscosity range of light to heavy oils. The main purpose of these tests, besides measuring the influence of viscosity upon the pump overall performance, was to supply detailed information on the energy transfer processes taking place in the pump internal components. To accomplish with that the pressure distribution along the flow path, through impellers and diffusers, from the pump inlet eye to the discharge section, was measured. Thus, besides measuring the flow rate, the total pressure difference, the speed, the power and the mean operation temperature, for a working liquid with various viscosities in a full range of operational conditions, the data showed the pressure evolution inside the pump. Later analyses revealed that there was a strong relationship between the flow hydrodynamics in successive pump devices in terms of head gain and viscous dissipation. This relationship was set by the pump operational operational conditions, flow rate and speed, and the fluid viscosity. In other words, how a diffuser performed depended on Reynolds number and the upstream flow through the impeller. Thus, any generalizing model dealing with the influence of fluid viscosity on the pump performance should account for these phenomena. For this reason, it is highly improbable that "black-box" approaches that neither consider the flow hydrodynamics of the successive connecting devices nor assess the influence of the Reynolds number on them could give proper viscosity correction factors for different pumps.
Examining Erosion Potential of Various Inflow Control Devices to Determine Duration of Performance
Authors: Visosky Jason M. , Clem Nicholas J. , Coronado Martin P. , Peterson Elmer R. 
Published: December 2007

Abstract
When producing long, horizontal zones, production rate is typically higher at the heel of the well than at the toe. The resulting imbalanced production profile may cause early water or gas breakthrough into the wellbore. Once coning occurs, well production may be severely decreased due to limited flow contribution from the toe. To eliminate this imbalance, inflow control devices (ICDs) are placed in each screen joint (sandstone formations) or debris barrier (carbonate formations) to balance the production influx profile across the entire lateral length and compensate for permeability variation. This creates equal production through each joint of screen to maximize recovery and rate.
Pressure drop is created through restriction or friction mechanisms. Restriction uses small holes or orifices to restrict flow. Friction utilizes surface friction of a long channel to create the required pressure drop. ICDs to effectively balance production inflow depend upon their ability to resist erosion. Because these ICDs are permanent downhole components, their long-term reliability is imperative.
Factors that determine erosion potential of ICD designs are fluid velocity, fluid particle concentration and design geometry. Calculations and computational fluid dynamics (CFD) modeling can be used to predict values for several factors independently, but not as a complete system. A full-scale erosion test is the most accurate way to demonstrate how the interaction of erosion factors affects the long-term reliability of downhole components.
This paper will detail the methodology behind ICD design, the use of CFD analysis in determining erosion potential, as well as the analysis of full-scale ICD erosion testing conducted at an independent testing laboratory.
Simulation of Dynamic Filtrate Loss During the Drilling of a Horizontal Well With Fractures and Its Impact on Well Performance
Authors: Wu Z. , Vaidya R. N. , Suryanarayana P. V. 
Published: December 2007

Abstract
In this paper, we present a new approach for modeling filtrate invasion during the drilling of a horizontal well with fractures, and the impact of its cleanup on well performance. The approach incorporates the drilling schedule and the experiment-based dynamic filter-loss data into multiphase reservoir simulator. Unlike the traditional leak off model in which the assumption of the piston-like displacement in the filtrate invaded zone, the fluid flow in the invaded and the reservoir zones are described by use of more realistic two-phase oil-gas flow equations which are solved under the dynamic boundary conditions of the leak off model and time-varying reservoir exposure due to drilling, tripping, completions and workovers. Since, impact of fractures on both invasion and flow-back is more pronounced in tight formations, this paper will focus on such formations.
In real drilling process, the initial dynamic mud-cake formation is critical for controlling filtrate loss. A dynamic fluid-loss model which reflects the spurt loss, non-Darcy and non-Newtonian characteristics of filtrate flow through the mud cake is coupled with the reservoir simulator. Mud properties and different events influence cake compression, dynamic cake deposition and cake erosion as well. The application of the dynamic filtrate loss model avoids the complexity in building a multi-parameter mathematical mud cake model without loss of generality. As in previous works, the dynamic filtrate loss model is based on actual special core tests.
Sensitivity analysis is conducted to study the influence of dynamic leakoff coefficient on the saturation distributions during the filtrate invasion and flowback. In existing experiments, only the leakoff coefficients for matrix are measured. The extrapolation of the dynamic leakoff coefficients for simulation of fluid loss into intersecting fractures is discussed. Driven by Buckley-Leverett equations, theoretical analysis is presented to emphasize the quantitatively spatial correlation between the invaded filtrate saturation and spatial permeability reduction in the invaded zone. Moreover, well performance influenced by the water blocking, relative permeability alteration and the damaged permeability variation are simulated. A horizontal well example is used to illustrate the flexibility of this approach. The results show that the dynamic leakoff coefficient significantly impacts the clean-up and well performance. The results also shed light on the relative value of hydraulically fracturing a conventional over-balanced drilled horizontal well, versus hydraulically fracturing the well after it is drilled underbalanced.