bluuebunny/crossref_metadata_2025_split huggingface dataset:
Risk Management/Functional Safety: A Practical Approach for End Users and System Integrators
Authors: Capelle Valentino Vande , Houtermans Michel 
Published: December 2007

Abstract
The objective of this paper is to demonstrate through a practical example how an end-user should deal with functional safety while designing a safety instrumented function and implementing it in a safety instrumented system. The paper starts with explaining the problems that exist inherently in safety systems. After understanding the problems the paper takes the reader from the verbal description of a safety function through the design of the architecture, the process for the selection of safety components, and the role of reliability analysis. After reading this paper the end-users understands the practical process for implementing the design of safety instrumented systems without going into detail of the requirements of the standard.
Drillable Tailpipe Disconnect: Used Successfully in More Than 120 Wells Worldwide
Authors: Rogers H. , Thornton P. , Fairchild M. , Austin D. 
Published: December 2007

Abstract
There are a number of challenges associated with setting cement plugs in an openhole well. Most importantly, drillpipe can become differentially stuck across a lost-circulation zone, and the plug may become contaminated with the intermixing of the mud resulting in inadequate isolation or insufficient strength.
Cement plugs are used for various reasons including healing losses, abandonment, and directional drilling. It is essential to these operations that a competent cement plug is placed the first time. The value of placing the designed cement plug properly is measured by nonproductive rig time, wasted material, and additional cementing services.
An innovative tool and a special process1 were designed to meet the challenges associated with setting cement plugs. The tool connects sacrificial/drillable tubing to the drillpipe and allows an operator to trip into the well and spot the cement plug across the problematic zone. Once cement is placed, the tool is disengaged and the operator trips the drillpipe out of the hole, leaving the cement plug and tubing undisturbed. The sacrificial tubing can be drillable; therefore, the operator can drill through the plug or commence other operations as required.
This paper discusses the challenges operators face when setting cement plugs and how the risk and nonproductive time are reduced with this innovative plug-setting process and tool. Well examples are documented from case histories to illustrate the success and lessons learned.
A Three-Phase Compressible Dual-Porosity Model for Streamline Simulation
Authors: Kozlova A. , Bratvedt F. , Bratvedt K. , Myasnikov A. 
Published: December 2007

Abstract
Streamline methods as a reservoir simulation tool have generated a great deal of interest in petroleum engineering because of the capability to calculate fluid flow in multi-million cell geological models with reasonable CPU times. Recently, streamline simulation has been applied to fractured reservoirs at the geo-scale. However, these simulations have been limited to two-phase incompressible systems. Commercial application of streamline methods to fractured reservoirs often requires the modeling of at least three compressible fluid phases.
Flow simulation of fractured reservoirs is commonly performed using a dual porosity model. The dual porosity system is modeled by using two coupled grids: one for matrix and one for fracture. The interaction between the two continua is modeled using matrix-fracture transfer functions. Until now, there were no mathematical models of dual porosity three-phase compressible flow for streamline simulators. To realize this model it was necessary to reformulate the matrix and fracture pressure equations. Conventional transfer function has been incorporated as a source/sink term, not only in the streamline saturation equations (as it was in incompressible case), but also in the pressure equation.
The dual porosity model has been implemented into a streamline simulator. This tool has its main application in the high resolution reservoir modeling domain for analyzing geological uncertainty, model ranking and screening, and dynamic model calibration using production data.
This paper describes the mathematical model for three-phase compressible dual porosity model for a streamline simulator and compares the results and run times of the streamline-based approach with a conventional dual porosity grid-based commercial simulator. The results from the streamline simulator for dual porosity show good agreement with those produced by a commercial finite difference simulator with order of magnitude improvement in simulation time.
The Effect of Wettability on Oil Recovery of Alkaline/Surfactant/Polymer Flooding
Authors: Dong Han , Hong Yuan , Rui Weng , Fan Dong 
Published: December 2007

Abstract
The present paper summarizes the laboratory studies of the effect of wettability on oil recovery of Alkaline/Surfactant/Polymer flooding. The wettability of water-wet Berea sandstone was altered into neutral-wet and oil-wet conditions by using organic reactants. The wettability index of each core sample was determined using a modified Amott imbibition method. The displacement efficiency of Alkaline/Surfactant/Polymer flooding and Polymer flooding at the different wetting conditions was evaluated by laboratory coreflood experiments. The experiment results indicate that the displacement efficiency of water flooding and ASP flooding is markedly affected by the wettability of the core. The wettability is one of the important factors to determine the oil recovery of water and ASP flooding. Water-wet and oil-wet conditions are favorable to obtain high enhanced oil recovery for ASP flooding. Contrast to ASP flooding, the influence of wetttability on oil recovery of polymer flooding was found to be minor for the three different wetting conditions. These results provide a guide to applying the ASP flooding and polymer flooding to the reservoirs with different wettability.
Case Study of New Slender Well Construction Technology
Authors: Howlett P. D. , Wardley M. T. , Black C. , Reed D. 
Published: December 2007

Abstract
This paper will describe the development, prototype testing, full well system test and field trial of an evolutionary slender well construction system. The system is a method of constructing oil and gas wells from close-clearance flush-jointed cemented liners from top to bottom to form the entire well.
Significant technical hurdles were overcome in the development of a system that is safe and practical to deploy whilst at the same time allowing drilling and completions engineers to plan the wells using accepted oil and gas well engineering methods. The paper will describe the technical hurdles to overcome to enable this method of well construction to become accepted.
This evolutionary method of constructing oil and gas wells has the potential to compete favorably with conventional techniques and other new technology methods already being deployed and could be used in a wide variety of well types.
In its full well construction format of four or more close-clearance liners, the cost of constructing the well can be reduced significantly, perhaps by more than 50%, whilst at the same time enhancing safety and reducing environmental impact. In its partial format of one to three close-clearance liners during a sidetrack or well extension, the available flow area across the zone of interest can be increased by 100% as a result of an increased tubular size deployed at total depth compared with convention. Figure 1 shows a comparison of the system to conventional techniques for full wells and Figure 2 shows the flow area increase of the system in its partial format.
3D Managed-Pressure Drilling Around a Salt Dome Using Coiled Tubing: A Case Study—Challenges and Solutions
Authors: Shaikh Abdul Mujeer Abdul Rehman 
Published: December 2007

Abstract
In last several years, the advantages and limitations of drilling with Coiled Tubing has been a subject of research and presentations. Coiled Tubing technology may not be the choice for drilling large diameter vertical holes, but may be the best technology for managing drilling condition within the reservoir. There has been an increasing use of Coiled Tubing technology for ‘side tracking' and ‘hole extension' would tend to support this belief.
Along with the evolution in Coiled Tubing drilling (CTD), there has been a growing acceptance of Managed Pressure Drilling (MPD). Hence the process of using this technology at a commercial level has begun.
The purpose of this paper is to discuss the efficiency of implementing Coiled Tubing technology with MPD conditions while drilling around a salt dome.
The paper proposes an example case study of drilling a 3-Dimensional well around a salt dome tracing two oil pockets at two different depths on flanks of the salt dome. It includes a detailed well plan and the challenges faced like fluid selection, BHP maintenance, complications in steering, and stress considerations around the salt dome and the solutions for the same. The paper also discusses the application of CTD and MPD in combating loss circulation, hole instability problems. It gives the comparison of drilling through a salt dome and drilling around it and the advantages of the latter.
Remediation of Production Loss Due to Proppant Flowback in Existing Wellbores
Authors: Nguyen P. D. , Stegent N. A. , Ingram S. R. 
Published: December 2007

Abstract
This paper presents the results of experimental study and field case histories of a remedial treatment technique using a low-viscosity consolidating agent placed into the propped fractures by coiled tubing (CT) or jointed pipe coupled with a pressure pulsing tool. The treatment fluids are designed to provide consolidation for previously placed proppant near the wellbore without damaging the permeability of the proppant pack. The consolidation treatment transforms the loosely packed proppant in the fractures and the formation sand close to the wellbore into cohesive, consolidated, yet highly permeable packs.
Laboratory flow testing indicates that the proppant pack in a fracture model under closure stress required low-strength bonds between proppant grains to withstand high production flow rates. Field case histories are also presented to discuss treatment procedures, precautions, and recommendations for implementing the treatment process. One major advantage of this remedial treatment method is the ability to place the treatment fluid into the propped fractures, regardless of the number of perforation intervals and their lengths without mechanical isolation between the intervals. The fluid placement efficiency of this process makes remediation economically feasible, especially in wells with marginal reserves.
Effect of Resident Water on Enhanced Coal Gas Recovery by Simultaneous CO2/N2 Injection
Authors: Jahediesfanjani H. , Civan F. 
Published: December 2007

Abstract
Majority of the coalbed methane reservoirs contain large amounts of water at initial reservoir conditions. Presence of water in the wet coal results from the chemical and physical bonding of coal with water, and influences the properties of coals. Frequently, dewatering is necessary prior to methane production from coal. However, some water still remains in the coal cleat and matrix after dewatering. The remaining water influences the coal gas isotherm, changes the coal gas phase diagram, and hence affects the performance of the enhanced coal gas recovery by simultaneous CO2/N2 injection.
Experimental and theoretical are carried out to establish the multi-component gas, water, and coal isotherms under various pressures and coal grain sizes for both low and high rank coals. The obtained isotherms are used to describe the adsorption/desorption processes involving the system of CO2/N2/CH4/water mixtures in coals. It is determined that presence of water reduces the injected CO2/N2 adsorption rates on both low and high rank coals, and the methane production rate, depending on the composition of the gas and water phases, and the prevailing experimental conditions. It is demonstrated that a higher ratio of the injected nitrogen is required for wet coals than for dry coals to enhance the gas recovery by CO2/N2 injection.
Analytical Solution of Single-Probe Tests in a Horizontal Well and its Application to Estimate Horizontal and Vertical Permeabilities
Authors: Sheng J. J. 
Published: December 2007

Abstract
During a single-probe test in a vertical well, the probe of a formation tester is set horizontally against a side wall of the borehole. In a horizontal well, the probe can be set either horizontally against a side wall, or vertically against the top or bottom wall of the borehole. When the probe is set horizontally against a side wall, the solution for a horizontal well is the same as that for a vertical well. However, when the probe is set vertically against the top or bottom wall, the solution for a horizontal well is not available in the literature. This paper presents an analytical solution to the described problem.
The solution shows that the relationship between the pressure drop and flow rate for a single-probe test in a horizontal well depends whether the probe is set vertically or horizontally against the borehole. One of the important applications of the solution is to estimate horizontal and vertical permeabilities from two probe tests. If two tests are conducted at the same measured depth, with the probe set vertically in one test, while horizontally in the other, two permeabilities are obtained. Then the horizontal and vertical permeabilities at the measured depth can be estimated by combining these two permeabilities.
The analytical solution is validated by numerical simulation, and the solution is shown to be the same as a published analytical solution for a vertical well in an isotropic formation. Examples to estimate horizontal and vertical permeabilities from synthetic tests are presented.
Fracture Stimulation Utilizing a Viscoelastic-Surfactant-Based System in the Morrow Sands in Southeast New Mexico
Authors: Pandey Vibhas J. , Itibrout Tarik , Adams Larry S. , Cowan Tracy L , Bustos Oscar A. 
Published: December 2007

Abstract
This paper discusses the selection criteria, design methodology, and analysis of hydraulic fracturing treatments pumped using a solids-free, liquid CO2 foam-based visco-elastic surfactant (VES) fluid system in Morrow Sand reservoirs located in Southeast New Mexico (SENM).
The wells discussed in the paper were completed in various Morrow Sand intervals around 10,500 ft with an average Bottom Hole Static Temperature (BHST) of 190°F. Wellbore completion constraints combined with reservoir parameters inclusive of low-pressured water sensitive formations, high rock Youngs' Modulus and unpredictable occurrence of water-bearing zones, lead to the selection of foamed VES fluids. This technology was successfully applied in the Morrow Sands in Eddy County of SENM. Fracture geometry analysis using surface treating pressures, radio-active tracers and production data, showed height growth containment and longer effective fracture half-lengths. Results also indicated successful stimulation past the cement squeezed intervals and temporary liner tie-backs run in to overcome lower pressure constraints. Finally, lower friction pressures helped in designing economical fracture stimulations for mature wellbores thereby generating an opportunity to recover otherwise bypassed hydrocarbon reserves.
Application of Relative Permeability Modifiers to Control Water Cut Following Hydraulic Fracturing in Western Siberia Oilfields—Russian Case History Study
Authors: Borodin E. G. , Vakhroushev P. E. , Stolyarov S. M. , Kalfayan L. J. 
Published: December 2007

Abstract
Due to geological characteristics and low permeability of Western Siberia hydrocarbon reservoirs, hydraulic fracturing is the most effective method for improving hydrocarbon production. During recent years the massive fracturing treatments in this area have led to a reduction of well candidates for this type of production enhancement technique. Currently the majority of selected wells for fracture stimulation are considered "risky" because of significant water cut increase after stimulation. The question arises - How to reduce water production while enhancing oil production?
This paper reviews 26 case histories exemplifying the use of Relatively Permeability Modifiers (RPM) in hydraulic fracturing to enhance oil recovery and control water production. Also results of laboratory studies are included to support the RPM-fracturing concept and placement techniques.
Restimulation: Candidate Selection Methodologies and Treatment Optimization
Authors: Moore L. P. , Ramakrishnan H. 
Published: December 2007

Abstract
Restimulation of existing wells represents a vast underexploited resource. A successful refracturing treatment is one that creates a fracture having higher fracture conductivity and/or penetrating an area of higher pore pressure than the previous fracture. Refracturing requirements are different in highly permeable formations (high fracture conductivity) as compared to low permeable ones (moderate fracture conductivity). Understanding these basic differences is essential to a successful restimulation.
In the past, candidate selection methodology has focused on underperforming wells. This simplistic approach has yielded disappointing results and has led to a common misconception that restimulations "don't work." Production statistics of a well alone may not offer an effective restimulation candidate selection methodology. Other parameters such as high BHP (remaining reservoir energy), recoverable reserves, ϕ-h1 and favorable response to original fracture jobs (IP) could play an equally important role, if not greater, in determining the success of restimulation. In fact, studies have shown that selecting poor or underperforming wells for restimulation is likely to result in worse outcomes than random selection of workover candidates.
Studies performed to date have concluded that no selection criteria can be universally applied to every situation; rather that the selection methodology for workover candidates must be customized to fit particular situations. This paper explores the common traits shared by fields likely to have underexploited restimulation potential and suggests methodologies that should be applied to various field types The case histories illustrated in this paper will highlight the various treatment parameters optimized for successful restimulation. The conclusions of this paper are based on our work in selecting restimulation candidates as well as published results of other operators. Application of the correct candidate selection methodology to a particular field type will inevitably lead to a higher success rate of restimulation walkovers and the capture of an underexploited resource.
Applicability of the Forchheimer Equation for Non-Darcy Flow in Porous Media
Authors: Huang H. , Ayoub J. 
Published: December 2007

Abstract
The subject of non-Darcy flow in hydraulically fractured wells has generated intense debates recently. One aspect of the discussion concerns the inertia resistance factor or the so-called beta factor β in the Forchheimer equation and whether the beta factor β for a proppant pack should be constant over the range of flow rates of practical interests. The problem was highlighted in a recent discussion by Batenburg and Milton-Tayler1 and the reply by Barree and Conway2 regarding paper SPE 893253 in the JPT in August 2005.
To properly assess all the arguments and to get a better understanding of the state-of-the-art on non-Darcy flow in porous media in general, literature concerning the theoretical basis of the Forchheimer equation and experimental work on the identification of flow regimes is reviewed. These areas of work provide insights into the applicability of the Forchheimer equation to conventional oilfield flow tests for proppant packs. Models for flow beyond the Forchheimer regime are also suggested.
Long-Term Scale Inhibition Using a Solid Scale Inhibitor in a Fracture Fluid
Authors: Szymczak S. , Brown J. M. , Noe S. , Gallup G. 
Published: December 2007

Abstract
Prolonged scale inhibition in excess of one year is a desirable benefit of oil and gas well formation squeeze treatments. Traditionally liquid inhibitors have given the requisite inhibitor residual for up to one year. Operators desire longer inhibition periods. This paper describes a new scale inhibitor technology that extends scale inhibition beyond one year.
All of the components of a hydraulic fracturing package must be compatible to insure that the rheology of the fluid is not affected. The placement of a scale inhibitor onto a formation requires a suitable inhibitor that will adsorb to the mineral surfaces and return slowly with the produced water. Adding a solid scale inhibitor to a frac package required limited compatibility testing and reformulation in order to meet the fluid integrity and product effectiveness criteria. The scale inhibitor dosage was designed for a three-year life.
The accepted method of monitoring the effectiveness of a scale inhibitor squeeze is through measuring the scale inhibitor residual in the produced water. Traditional liquid scale inhibitors give a high initial residual (&gt;1000-ppm) and deplete to a minimal level (1-10 ppm) within a year. The solid inhibitor placed on the formation during the frac released a residual below 50 ppm at the first reading and has maintained an acceptable level for the life of the placement (as of this writing the residuals are still above the minimum level).
Operators of offshore and remote area wells that are prone to scale deposition must undertake significant intervention measures to remediate scale deposition.1 This new chemical technology extends the life of a scale inhibitor placement beyond the current expectations. The advancement of this technology will save operators money and encourage the development of properties that might be viewed unprofitable due to the high frequency and cost of intervention.
Effects of High Oil Viscosity on Oil/Gas Flow Behavior in Horizontal Pipes
Authors: Gokcal B. , Wang Q. , Zhang H. -Q. , Sarica C. 
Published: December 2007

Abstract
Oil-gas pipe flows are expected to exhibit significantly different behavior at high oil viscosities. Effects of high viscosity oil on flow pattern, pressure gradient and liquid holdup are experimentally observed and differences in flow behavior of high and low viscosity oils are identified. The experiments are performed on a flow loop with a test section of 50.8-mm ID and 18.9-m long horizontal pipe. Superficial liquid and gas velocities vary from 0.01 to 1.75 m/s and from 0.1 to 20 m/s, respectively. Oil viscosities from 0.181 to 0.587 Pa·s are investigated. The experimental results are used to evaluate the performances of existing models for flow pattern and hydrodynamics predictions. Comparisons of the data with the existing models show significant discrepancies at high oil viscosities. Possible reasons for these discrepancies are carefully examined. Some modifications are identified and implemented to the closure relationships employed in the Zhang et al.1 model. After these modifications, the model predictions provide better agreement with experimental results for flow pattern transition, pressure gradient and liquid holdup.