bluuebunny/crossref_metadata_2025_split huggingface dataset:
Meeting the 10km Drilling Challenge
Authors: Modi S. , Mason C.J. , Tooms P.J. , Conran G. 
Published: December 2007

Abstract
This paper discusses the planning and preparation process for drilling and completing a 10km departure well at the Wytch Farm Oilfield in Southern England.
An 8km departure well was drilled at Wytch Farm during 1995. At the time, this was at the limit of drilling operations. Some fundamental changes involving new technology, operational practices and techniques have been necessary to enable this well to be drilled.
More specifically, the paper will describe the directional drilling techniques necessary to enable the reservoir interval to be accessed. Research and development work performed by the drilling team to identify mechanical limitations in drilling operations at this departure are also examined. This includes a comprehensive review of offset well data to determine friction factors for all operations and concomitant measures adopted to limit rotary torques and drags to workable levels. The other major focus of this paper is to appreciate the mechanism by which drilling muds are lost to the permeable reservoir and describe methodologies employed to overcome this problem.
The paper will also discuss recent experience with the application of partially floating casing, rotary steerable drilling systems and running and cementing long liners.
Completion and intervention challenges are also examined with an analysis of future requirements.

Introduction
The development of the offshore extension of the BP operated Wytch Farm Oilfield, located on the South coast of Britain, utilising extended reach (ER) wells into the offshore part of the Sherwood sandstone reservoir has been extensively documented in a series of technical papers [1], [2] and [3]. (Figure 1). The current phase of the development is to tap into significant reserves located at reservoir departures in excess of 10km.

The Drilling Challenge.
The section of the reservoir targeted by this Ultra-Reach well (Measured Depth : True Vertical Depth ratio &gt;5), M-11, lies between 8km and 10km departure from the 'M Wellsite' where the Deutag T-47 rig is located. This site, specially constructed to access the offshore portion of the reservoir currently contains 10 extended reach wells and yields over half of the total 110,000 bopd production at Wytch Farm.
The challenge is to safely and efficiently drill and complete a 10km departure well into the target area to access oil in place of 24mm STB. A single horizontal well into this target is expected to recover some 25–35% of these reserves. Although this is likely to be the most expensive well drilled at Wytch Farm, the significant reserves that it will access are critical to the long term profitability of the field. The well design is the culmination of over a year's evaluation, design and planning, providing an excellent test of the industry's capabilities. Successful delivery of this well will have a significant impact on the industry to access reserves that a decade ago would have required major capital expenditure, in the shape of new facilities, to recover.
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Polymer-Free Fluid for Hydraulic Fracturing
Authors: Samuel Mathew , Card Roger J. , Nelson Erik B. , Brown J. Ernest , Vinod P.S. , Temple Harry L. , Qu Qi , Fu Dan K. 
Published: December 2007

Abstract
Polymer residues that stay in the fracture after a hydraulic fracturing treatment can limit treatment effectiveness. A new and easy-to-prepare, polymer-free fluid that consists of a quaternary ammonium salt derived from a long-chain fatty acid is described. In brine, it builds viscosity due to the formation of highly entangled worm-like micelles. The micelles have a gross structure similar to a polymer chain. Since the viscosity of the fluid depends on the nature of micelles, the fluid can be broken by changing this micellar structure. The breaking occurs when the fluid is exposed to hydrocarbons or diluted with formation waters. Therefore, conventional breakers are not required, and the produced oil or gas can act as breakers for this fluid system.
The structural characteristics of the polymer-free surfactant fluid to its chemical and physical properties are correlated in this paper. Structure, rheology, fluid loss and conductivity of this surfactant fluid together with its production data are presented.

Introduction
Fracturing fluid is a very critical component of a hydraulic fracturing treatment. Selection of the fracturing fluid, job design, and well turnaround procedure all help to determine the production of a well after a stimulation by hydraulic fracturing. A fracturing fluid should provide sufficient viscosity to suspend and transport proppant into the fracture, and should break into a low-viscosity fluid after the job is completed. This will facilitate the fracture to clean up by allowing rapid flowback of fluid to the surface.
Analysis of the fluid returned to the surface (flowback fluid) after hydraulic fracturing indicates that as little as 30 to 45% of the guar-based polymer pumped during the treatment returned from the well during the flowback period. Polymer residues that remain in the fracture significantly contribute to a lowered proppant-pack permeability leading to a loss in fracture treatment effectiveness.
The field success of a viscoelastic surfactant-based (VES) polymer-free fluid in frac-pack applications led to the development of a similar fluid for hydraulic fracturing.
The VES fluid can be used for the fracturing treatment of potentially all gas and oil wells below 240 F. The principal advantage of this fluid system is its operational simplicity. This fluid is easy to prepare and requires less equipment at the wellsite This fluid does not require polymer hydration, biocides, crosslinkers, or breakers. The hydrocarbons produced, or dilution of VES gel by other formation fluids, can break this fluid.
This new fluid has been used for the successful execution of more than 250 fracturing jobs. Results from representative treatments are presented.
Application of a Monte Carlo Technique in Gas Plant Design
Authors: Guttormson Dean L. , Snyder Louis J. , Palmatier Everett D. 
Published: December 2007

Abstract
This paper describes two illustrative examples demonstrating the application of Monte Carlo techniques to gas process design. In addition, a detailed discussion is presented of the characteristics of the Monte Carlo procedure. In the first example Monte Carlo procedure. In the first example Monte Carlo simulation is used to determine the distribution of required MEA circulation rates to sweeten gas in a proposed installation. A simple problem formulation is used; therefore, it is possible to test the sensitivity of the calculated circulation rate distribution to the number of Monte Carlo events and to the selected probability distribution. In the second example, the probability distribution. In the second example, the optimum size of a lean oil absorption plant is determined. Feed rate and composition together with product prices are selected as random variables. Distributions of present-value profit are generated for several plant sizes. profit are generated for several plant sizes. Optimum plant size is selected to maximize the mean present-value profit.

Introduction
In designing gas processing facilities, plant size or capacity must be established prior plant size or capacity must be established prior to determining process configuration and operating conditions. Establishing the optimum capacity is complicated in that plant inputs and economic constraints, such as feed volume and composition, product price, and equipment operation, may not be known with certainty. This paper demonstrates use of Monte Carlo techniques in gas plant design problems when system inputs are uncertain.
To use Monte Carlo techniques in analyzing gas processing projects, plant inputs and economic constraints that characterize the project must first be defined. These project project must first be defined. These project parameters fall into two classes: deterministic parameters fall into two classes: deterministic and stochastic variables. Deterministic variables have a known value, but can vary with time (e.g., the gas price in a long-term gas sales contract). Stochastic variables are not known with certainty and are described by a probability distribution spanning a range of probability distribution spanning a range of values. For most variables a triangular distribution adequately relates the value of a stochastic variable to its minimum, maximum and expected value.
Next, appropriate yardsticks for comparing investment decisions must be selected. Present-value profit and investor's interest rate are Present-value profit and investor's interest rate are commonly used economic yardsticks. It may be preferred to use key process variables, plant preferred to use key process variables, plant investment, or product output to characterize performance so that the result may be used in a performance so that the result may be used in a subsequent economic analysis.
Cement Evaluation and Casing Inspection With Advanced Ultrasonic Scanning Methods
Authors: Graham W.L. , Silva C.I. , Leimkuhler J.M. , de Kock A.J. 
Published: December 2007

Abstract
This paper will demonstrate cased-hole applications of a new ultrasonic scanning tool. Field logs are presented from environments containing various wellbore, casing, and cement slurry types. Cement evaluation and casing inspection examples will include logs from wells with heavy completion fluids, lightweight cements, heavyweight casing, and hastelloy pipe (used in highly corrosive environments).
Very high horizontal and vertical sampling rates permit simultaneous cement evaluation and casing inspection. The data are corrected for direction and tool rotation using a navigation package. Data such as acoustic impedance, cement compressive strength, casing thickness, casing outer diameter and/or radius, casing ovality, tool eccentricity, and 40 to 100 calipers may all be recorded in real time in conventional or imaging formats. Improved processing software provide two- and three-dimensional images.
It was observed that differing wellbore and casing conditions require different logging parameters (such as scan rate and sample density). Thus, the mechanical and electrical configuration of the tools are flexible to maximize signal response in all possible downhole conditions. Multiple scanning heads with selectable transducer characteristics are available. Downhole processing also reduces telemetry demands and allows other tools to be combined with the new scanning device to provide additional real-time data without reducing logging speed or delaying analysis processing until after logging.

Introduction
Downhole ultrasonic scanners have been used primarily for imaging wellbores. A new scanner that furnishes improved images and that offers remarkable casing inspection and cement evaluation capabilities has been developed and field proven. The new device operates in two modes: image mode and cased-hole mode.
In image mode, the scanner evaluates only the "inner" surface of the target (the formation bounding the wellbore or the inner wall of the casing). High vertical and azimuthal sampling provides high-resolution, two and three-dimensional images. These images are useful in locating fractures, identifying borehole breakout, delineating bed boundaries, studying formation textural features along the borehole wall, and evaluating casing integrity by revealing distortion, wear, holes, parting, and other anomalies on the inner wall of the casing.
When cement evaluation or a more complete casing assessment is needed, the ultrasonic scanner operates in cased-hole mode. The full circumferential maps of casing thickness and acoustic impedance generated from the measurements made in this mode can be used to reveal thinned casing and to clearly distinguish between cement and fluids in the annular space behind casing. In cased-hole mode, a significant part of the acoustic waveform is processed. Thus, high telemetry data rates, intense processing capabilities, and selective transducer frequencies are required.
Influence of Areal Anisotropy on Horizontal Well Performance
Authors: Yildiz Turhan , Ozkan Erdal 
Published: December 2007

Abstract
The objective in this paper is to investigate the influence of well orientation and areal anisotropy on the transient pressure response of a horizontal well whose axis deviates from the principal areal permeability directions. The investigation is based on an analytical solution in Laplace space. It is observed that areal anisotropy and well azimuth angle have a substantial effect on transient pressure behavior especially at early and intermediate flow times. If the well axis is not normal to the maximum permeability direction, the intermediate time linear flow does not appear.
Synthetic drawdown tests were analyzed to estimate the principal permeabilities and skin due to damage using conventional straightline methods. The estimated principal permeabilities from the simulated tests significantly deviated from the input values due to azimuth angle. However, the estimated geometric mean areal permeability (kH=kxky) and 3D equivalent system permeability (k=kxkykz3) agreed well with the input values.
Determination of Pressure-Transient and Productivity Data for Deviated Wells in Layered Reservoirs
Authors: Larsen Leif 
Published: December 2007

Abstract
Analytical methods are presented to determine pressure-transient and productivity data for deviated wells in layered reservoirs. The computational methods, which are based on Laplace transforms, can be used to generate type curves for use in direct analyses of pressure-transient data and to determine the effective skin of such wells for use in productivity computations.
Early Determination of Reservoir Flow Units Using an Integrated Petrophysical Method
Authors: Gunter G. W. , Finneran J. M. , Hartmann D. J. , Miller J. D. 
Published: December 2007

Abstract
This paper uses case histories to introduce a graphical method for easily quantifying reservoir flow units based on geologic framework, petrophysical rock/pore types, storage capacity, flow capacity, and reservoir process speed. Using these parameters and four graphical tools, this paper outlines a quantitative approach to transform rock-type-based zonations into petrophysically based flow units that can be input into a numerical flow simulator. This method provides a tool for determining the minimum number of flow units to input into a numerical flow simulator that honors the foot-by-foot characteristics at the wellbore.
A flow unit is a stratigraphically continuous interval of similar reservoir process speed that maintains the geologic framework and characteristics of rock types. Rock types are representative reservoir units with a distinct porosity-permeability relationship and a unique water saturation for a given height above free water level.
The ideal data for this method is continuous core porosity, permeability, and saturation information drawn from throughout the entire reservoir. If such a data set is not available, it is necessary to calibrate wireline log data with core information to produce reliable estimates of porosity, permeability, and saturation. A full discussion of these data transforms are beyond the scope of this paper.
The four graphical tools used to determine flow units are: Winland porosity-permeability cross plot, Stratigraphic Flow Profile (SFP), Stratigraphic Modified Lorenz Plot (SMLP) and Modified Lorenz Plot (MLP).
This method begins by establishing rock types within a geologic framework. The geologic framework allows the flow units to be interpreted within a sequence stratigraphic model determining well-to-well correlation strategies. The key flow unit characteristics to be identified are barriers (seal to flow), speed zones (conduits), and baffles (zones that throttle fluid movement).
This integrated, petrophysically based method of determining flow units has been successfully used in a wide array of reservoirs. We have applied it to young, unconsolidated sediments; structurally complex naturally fractured/vuggy carbonates; low permeability "tight" formation gas sands; diagenetically altered carbonates; complex mixed lithologies; and interbedded sand-shale sequences.
The earlier in the life of a reservoir this process is used, the greater the understanding of future reservoir performance. This method allows the user to employ the least number of flow units and honor the character of the foot by foot data for simulation studies.
Evaluation of a Gas Well Testing Method
Authors: Lee John W. , Harrell Robert R. , McCain William D. 
Published: December 2007

Abstract
In principle, drawdown tests provide data that allow a complete characterization of a gas well. Unfortunately, rapid analysis of drawdown test data is generally regarded as possible only for the special case in which production rate is maintained strictly constant for the duration of the drawdown test. In many tests, constant production rates are either inconvenient or impossible to maintain; analysis of data from such tests has been thought to require the tedious use of superposition, which, as a practical matter, means that a computer must be used practical matter, means that a computer must be used to perform the necessary arithmetic.
Actually, a technique for analyzing variable-rate drawdown test data easily and rapidly has been in the literature since 1965. This method, proposed by Winestock and Colpitts, is virtually as rapid as conventional techniques used to analyze constant-rate drawdown tests; and it provides estimates of formation permeability-thickness product, skin factor, and permeability-thickness product, skin factor, and turbulence effects. Knowledge of these parameters allows more accurate predictions of current and future deliverability of a tested well than are usually possible with conventional back pressure tests or isochronal tests.
This paper reports the results of a study which was performed to test the validity of the analysis technique proposed by Winestock and Colpitts. The study, which was based on a numerical simulation of the pressure-production history of a gas well, showed that the analysis technique of Winestock and Colpitts is indeed valid for pressure drawdown data obtained with smoothly varying production rates.

Introduction
To completely characterize a gas well, a testing program should provide an estimate of reservoir permeability-thickness product, information about the extent of well damage, information leading to estimates of the possible effect of stimulation, and deliverability. Unfortunately, conventional gas well testing methods do not provide all this information. For example, the most common method is the Back-Pressure Test. This test has two major weaknesses: First, this test, at best, provides only deliverability estimates, and gives none of the other information needed to completely characterize a gas well.
Reservoir Modeling Using Scale Dependent Data
Authors: Panda M.N. , Mosher C. , Chopra A.K. 
Published: December 2007

Abstract
A reservoir description incorporating the precision and scale of all available data (geological, petrophysical, seismic, tracer and well test data) is critical for reservoir modeling. The heterogeneous variables sampled by these data are composed of several superimposed random functions, each characterized by a unique spatial and temporal scale or support. For example, core, well log, well test and seismic data have supports ranging from inches to thousands of feet.
Current geostatistical methods map lithofacies, porosity, and permeability on a network of grid nodes called the geologic modeling cells. Pseudo point properties that assimilate information from all available data are modeled onto model cells using one of several available conditional simulation techniques. Some methods attempt to combine data with varying support and data with multiple scale support through simple correlations. For example, one approach to incorporate geophysical data is to use a direct transform of the seismic signal to rock properties through a linear regression or crossplot. Reservoir models built using such linear correlations tend to be case specific with little generality.
This paper presents a method for identifying the impact of multi-scale data (data that measure average property over multiple flow units) on reservoir modeling. It examines the information about the reservoir system each data type carries. For example, what fraction of core scale variability is captured by well log data. We also present a consistent method for integrating multi-scale data. Through a series of numerical simulations, we show the impact of heterogeneity of reservoir properties on the fluid flow performance.

Introduction
Reservoir modeling is a systematic approach to estimate constitutive properties based on a few experimental observations. In other words, it is an algorithm that produces multi-dimensional distribution of rock properties forming a prototype of the actual reservoir. The main goal is to impose the same boundary conditions as in the reservoir and obtain actual responses. The benefits are that once an appropriate model is formed it can be examined for a variety of boundary conditions.
Conjugate Fracture Zones: Potential "Sweet Spot" Reservoirs Within Regional Parallel-Fracture Systems
Authors: Lorenz John C. 
Published: December 2007

Abstract
The mesh of permeability that can be provided by sets of intersecting conjugate fractures offers significant conductivity within a reservoir. This plumbing system will be an enhancement over not only matrix permeability values, but also over the permeability provided by related sets of sub-parallel, bed-normal, regional extension fractures. Conditions under which regional extension fractures have developed locally into conjugate fractures are described, offering possible exploration scenarios. Conjugate fractures may occur as bed-normal fractures with a vertical axis of intersection or as steeply inclined fractures with a horizontal axis of intersection, depending on the orientation of the principal stresses during fracturing. Increases in stress magnitudes and anisotropy during production drawdown of reservoir pressures may cause shear offsets along conjugate fractures. This will further enhance the fracture permeability, but only up to the point at which fault gouge begins to develop. Conductivity will not be enhanced, however, where conjugate fractures developed as deformation or shear bands, which are typically permeability barriers.
Techniques for Measuring Wax Thickness During Single and Multiphase Flow
Authors: Chen X. T. , Butler T. , Volk M. , Brill J. P. 
Published: December 2007

Abstract
Accurate measurement of wax thickness deposited on a cold pipe wall is of vital importance to the development of predictive models for paraffin deposition in flowlines and wellbores. Existing wax thickness measurement techniques, including pigging, spool piece, pressure drop, and heat transfer methods, are critically reviewed. An on-line wax thickness measurement technique, named the liquid displacement-level detection method (LD-LD), is presented. This new method is capable of giving both longitudinal and circumferential wax thickness distributions as well as the total wax deposit volume for single-phase and multiphase flow in pipes.