bluuebunny/crossref_metadata_2025 huggingface dataset:
Compressible Streamline-Based Simulation With Changes in Oil Composition
Authors: Beraldo V. T. , Blunt M. J. , Schiozer D. J.
Published: September 2008

There are several oil fields offshore Brazil with horizontal oil density variations. API tracking, that is available in some commercial finite difference simulators, can deal with such cases by allowing definition of an initial oil gravity distribution and tracking variations of oil density, due to the movement of oil.

Streamline-based simulators can be much faster than conventional finite difference simulators when applied to large and heterogeneous models. However, this approach is most accurate and efficient when it is assumed that the rock and fluids are incompressible. In previous work (Beraldo et al, 2007), we presented an incompressible formulation for streamline simulation with an API Tracking option using two components in the oleic phase.

This paper presents a compressible formulation for streamlines that also considers API tracking. It extends the work of Cheng et al. (2006) and Osako and Datta-Gupta (2007) by consistently accounting for flux of mass and volume along streamlines. We describe how mass and volume can be mapped between the underlying grid and streamlines to minimize mass balance errors and how consideration of cumulative volume in a streamline can substitute for time-of-flight.

The method was implemented in a three-dimensional two-phase streamline-based simulator. Tests based on a Brazilian oilfield model and on the SPE10th Comparative Case demonstrate that the implementation can reproduce the results of a conventional simulator, while being substantially faster for finely-resolved models, even when compressibility is significant.
An Analysis of Noise Characteristics of Drill Bits
Authors: Gradl Christian , Eustes Alfred W. , Thonhauser Gerhard
Published: September 2008

There have been papers that analyse the relationship between drill bit design and its vibrational characteristics. These papers typically are based on the analysis of three-axis down-hole vibration sensors located near the bit. In this paper the authors take a simpler approach. Using a standard microphone literally pointed at the bit, they record the noise of the bit/rock interaction while drilling and analyse the resulting noise for basic information on the bit.

The data were gathered at the Colorado School of Mines in Golden, Colorado. The noise of a PDC, roller cone, and diamond bit were recorded under various operational parameters using microphones and a uniaxial geophone (used for confirming the data recorded on the microphones). Using a Fast Fourier Transform, the frequency spectra were extracted from the recorded data.

Summarizing the results of the analysis of the roller cone bit, the PDC, and the natural diamond bit, major differences in their frequency characteristics could be detected and furthermore, for drag bits, the frequency characteristics could be related to the bit's design. The frequency spectra of the roller cone bit can best be described with a general high amplitude level that is relatively evenly distributed over the whole frequency spectrum. The drag bit data showed a strong relationship between the number of cutting elements and frequency peaks on a plot of amplitude vs. cycles per revolution. Frequency peaks were observed at multiples of the number of cutting elements. In general this relationship was strongly visible on the PDC bit data but not a strong on the diamond bit data. The conclusion is that bit characteristics can be determined using only acoustical data (ie. the noise of a bit). Potential applications of this research include detecting and diagnosing bit problems (e.g. broken teeth, bit balling) in real time using acoustic data.
Improving Reservoir Characterization Using Accurate Flow-Rate History
Authors: Pinilla E. J. , Pardo C. H. , Warlick L. M. , Al-Shobaili Y. M. , Aftab M. N. , Khan A. , Rahman N. M. A.
Published: September 2008

Well testing is one of the most effective means to characterize hydrocarbon reservoirs under dynamic conditions. Such characterization of reservoirs is as accurate as the data used for interpretation. It is, therefore, essential to have accurate measurements of both rates and pressures due to their complementary nature. Although pressure measurements are accurate, one needs to pay more attention to the rate measurements, especially during the early stages of exploration. Accurate measurements of gas and liquid flow rates using a separator are very difficult because of poor separation among the three phases when the flowing oil is heavy and viscous. This condition gets even worse in situations like low gas rates, low density contrasts among liquids, contamination of the different effluents after separation, and well instabilities leading to carry-over or carry-under.

Multiphase metering based on a dual-energy Venturi technology enables simultaneous, accurate rate measurements of oil, water and gas phases produced from development, exploration or appraisal wells, while the downhole gauges measure the pressures.

This paper presents comprehensive results from field tests conducted with multiphase meters in carbonate reservoirs producing Arabian heavy oil. These tests were conducted with production logging tools enabling characterization of laminated layers. Complete analyses of downhole gauge data are presented to demonstrate how the characterization of investigated formations improves with accurate rate measurements. It is also shown that if the rate measurements are not rigorous, it might lead to a misleading interpretation of the acquired pressure data.
The Methods for Determining the Viability of Electronic Textbooks and Their Hardware for Use in the University Environment: The Trips, Tricks, and Traps for Their Selection
Authors: Platt F. M. , Hausman L. A.
Published: September 2008

Technology for teaching has changed dramatically over the years from pen and paper to typed pages to the latest technology, electronic print. This paper investigates the potential for their use in the University environment. Part of this problem is the determination of what is available, where to find it and what method to display it for the student to use. A final item of this list is cost for the application and hardware. Is it comparable to hard copy paper books?

Electronic books have been in the market for several years but their usability in the classroom has been limited. Books must be downloaded to some type of device for the student to access. Until the reduction in hardware cost the primary application or delivery device was the desktop computer. With the reduction in cost of laptops this becomes more usable and with the new electronic readers this becomes even more viable. Now the cost of the reader is comparable to the savings in using electronic books.

This work will investigate the viability of electronic books for Petroleum Engineering. We will include an analysis of what is available, the functionality of the readers as well as an analysis of the cost of the application. A sidebar to this task is the ability for the engineer to carry his/her library with them into the field. Something unheard of ten years ago. An engineer on a project will not have to go back to the office to find a reference for their project, it will either be on his laptop or on an electronic reader.

Analysis of this topic would not be complete without discussion of media format. Will a format used today be available in ten years? Will a book bought today be useable on hardware yet to be created? These are questions that will be addressed in this paper. The primary conclusion of this paper is that electronic books are a viable method but proper care must be used to determine the optimum solution. The cost of replacement in the event of an incorrect selection could be disastrous.
Valuing Oil and Gas Options by Least-Squares Monte Carlo Simulation
Authors: Willigers B. J. A. , Bratvold R. B.
Published: September 2008

Least-Squares Monte Carlo simulation (LSM) is a promising new technique for valuing real options that has received little or no attention in the oil and gas industry. In this paper, we will demonstrate how LSM can handle more realistic valuation situations including the ability to (i) handle more realistic (probabilistic) price models and (ii) deal with multiple, possibly correlated, uncertain variables.

The LSM method is applied here to an economics problem faced by many operators: What is the value of a gas field given the decision to trade the gas on the spot market as opposed to selling the gas through a long-term supply contract? A company that chooses to trade gas can decide when and how much to produce and can profit from changing market conditions, as by increasing production during a high-price environment.

Three uncertainties have been modeled: the gas price, the operational costs, and the rate of production decline. Increasing profitability associated with rising hydrocarbon prices is typically partially offset by increasing expenditures. Hence the costs have been correlated with the gas price. The expectation of the remaining reserves is continuously adjusted on the basis of the performance of the field. The latter is simulated by stochastically modeling the rate of production decline.

The paper shows that a gas field that can be produced and abandoned at will has large value of flexibility. The Net Present Value of such an asset will underestimate the true economic value. A further benefit of using the real option valuation approach discussed here is that the valuation procedure produces a strategy map showing actions within the project, not just numbers.
Thermally-Enhanced Evaporation Process in Fractured Reservoirs— A Pore-Network Study
Authors: Tajer Ehsan S. , Yortsos Yannis C.
Published: September 2008

We study evaporation processes in fractured reservoirs under thermally enhanced conditions using pore-network models. The emphasis is on understanding evaporation phenomena and the combined effects of capillarity and viscous forces as are modified by the presence of thermal gradients and an applied heat flux. The temperature dependence of equilibrium vapor concentration and surface tension and macroscopic corner films are included.

The phase distribution evolution, liquid saturation, film flow and recovery rates are obtained as functions of dimensionless parameters in the two cases of positive and negative temperature gradients. The results are obtained without the use of empirical or ad hoc coefficients and parameters.

Strong evaporation effects under thermal conditions, associated with the variation of equilibrium concentrations, are clearly shown. The influence of surface tension variation induced by thermal gradients leads to destabilizing or stabilizing invasion percolation fronts, depending on the direction of the thermal gradient.

The paper finds application to the recovery of volatile oils from fractured or heterogeneous reservoirs by thermal processes, such as steam injection.
Using Industry Standards as a Way to Predict Sand Performance and Approve Sand Deposits: Is there a Catch 22?
Authors: Brannon H. D. , Stephenson C. J. , Freeman E. R. , Anschutz D. A. , Renkes J. J. , Rickards A. R.
Published: September 2008

The sands employed as fracturing proppant have been historically qualified for that purpose based upon their ability to meet quality standards described by the American Petroleum Institute (API, 1995) and more recently, by the International Organization for Standardization (ISO, 2006). Notable products meeting those standards include white sands from the Ottawa deposits in the north central United States, and the so-called brown sands from deposits in central or the "heart" of Texas. Until recent times, these "quality" sand deposits provided sufficient supplies for the ongoing needs. However, the unprecedented surge of hydraulic fracturing activities over the past few years has resulted in demand outpacing the supply for sands that meet these requirements.

Consequently, many ‘new’ sand deposits are being evaluated for use in fracturing applications, but unfortunately, a great many of those when subjected to API / ISO standards fail to make the grade in one area or another. Interestingly, it is commonly similar criteria which are being failed including acid solubility, sphericity & roundness, crush strength, and particle distribution. Thus, one is given cause to question the relevance of some testing practices on ‘real world’ performance of sand in a fracturing treatment.

It is this point which illustrates a "Catch 22". A sand can pass industry standards as a quality proppant, but it may not necessarily meet the performance, or conductivity, requirements of a reservoir. Yet, as this study demonstrates, a sand source that fails some of the standard testing parameters might still meet the flow capacity needs of a reservoir.

One can better understand the role that industry standards play in predicting sand performance and in approving sand deposits through closer examination. So, first, a discussion of some of the individual quality standards and their influence will be shared. Secondly, empirical data will demonstrate relative impact on sand performance, via conductivity, when one or more of qualifying parameters fails to pass. Lastly, guidance will be provided for the use of sands and other proppants, which although technically are unacceptable per industry standards, may be perfectly acceptable as ‘fit-for-purpose’ proppants in at least some segment of the fracturing market.
Study of New Solutions for Acid-Resistant Cements
Authors: Lécolier E. , Rivereau A. , Ferrer N. , Audibert A. , Longaygue X
Published: September 2008

In the near future, the production of oilfields with high contents of associated sour gases will increase. Research on technologies to produce such fields are therefore of utmost importance. Due to the presence of corrosive gas, special attention has to be paid to the design of well materials (casing, cementing materials). However, published data on degradation mechanisms of cement-based materials exposed to H2S environments are very scarce. When placed in contact with acid fluid, portland cement will dissolve and become, at some time, fully degraded. In this case, the zonal isolation will be no more effective. New solutions are required to ensure long-term integrity of cementing materials. One potential solution is to incorporate chemicals in the cementitious matrix. The key idea is to incorporate additives that react preferentially with H2S and not with hydrated phases of the cement. The goal of this work was to assess this solution.

The paper is dealing with cement formulations that incorporate mineral admixtures. These mineral admixtures have been chosen because of their high chemical affinity with hydrogen sulphide. We first give properties (density, compressive strength, rheological behaviour) of the novel formulations. Then we describe the static ageing tests performed in H2S-saturated brine at 120°C and 15 MPa. By combining different analytical techniques, the chemical evolution of the new formulations has been investigated.

The results are dependent on the nature of the reactive mineral admixture. We show that, in some particular case, the incorporation of specific mineral admixtures leads to a strong damaging effect for the cement matrix. Consequently, for the design of H2S-resistant cement, these specific mineral admixtures should be discarded. The proposed solution (addition of reactive chemicals) is promising but requires more investigation in order to carefully control the reactivity of the different chemical species.
Determination of In-situ Two-Phase Flow Properties through Downhole Fluid Movement Monitoring
Authors: Kuchuk Fikri , Zhan Lang , Ma S. Mark , Al-Shahri Ali M. , Ramakrishnan T. S. , Altundas Bilgin , Zeybek Murat , de Loubens Romain , Chugunov Nikita
Published: September 2008

In this paper, we present a novel method for in situ estimation of two-phase transport properties of porous media using time-lapse resistivity, pressure, and flow rate data from a permanent downhole Electrode Resistivity Array (ERA) and pressure, and a production logging tool. The primary objective of this Fluid Movement Monitoring (FMM) setup and experiment is to provide in-situ measurements required to determine multiphase flow properties, such as relative permeabilities and capillary pressures. Continuous monitoring of oil displacement by injected water in all the permeable zones was conducted in a carbonate reservoir in Saudi Arabia.

The field experiment was divided into two stages: 1) Selection of the well location, coring and logging, experimental setup and completion designs, cleanup, production profiles, pressure transient buildup tests, water injection and subsequent production of all injected water, and collection of all relevant data that include time-lapse pressure, production and injection profiles, and resistivity; and 2) Interpretation of all the data acquired from different sources, development of algorithms/software to compute the movement of the injected fluid through the reservoir, and the inversion of multi-source and multi-physics measurements. This monitoring experiment was achieved through an integrated interpretation of different data sets such as transient drawdown/injection and drawdown/buildup tests, 3D deep resistivity, production and injection profiles, openhole log, and core measurements. This approach is new to the industry and the first field experiment for direct in situ determination of two-phase flow properties. The key outcome of this field experiment is a full verification of the permanent downhole resistivity array and pressure sensor experimental setup for estimating in-situ layer relative permeabilities and capillary pressure and monitoring water movement inside the formation. This allowed multiphase characterization of the formation around the measurement well to a radial depth of tens of meters.
Maximizing Reservoir Contact in the Oseberg Field Using a New Azimuthal Deep-Reading Technology
Authors: Bittar M. , Hveding F , Clegg N. , Johnston J. , Solberg P. , Mangeroy Gro
Published: September 2008

The industry today is challenged to maximize recovery from existing assets, meaning that increasingly complex and thin reservoirs must be drilled and evaluated. Consequently, reservoir management efforts aimed at maximizing production through optimal wellbore placement require increasingly sophisticated geosteering and formation evaluation capabilities.

This paper discusses the use of a newly deployed azimuthal, deep-reading, resistivity tool for geosteering and formation evaluation while drilling in the Oseberg Field. This tool, combined with well steering software, gave geosteering engineers the ability to steer the well not only on variations in resistivity but on direct measurements of resistivity that delineated layer boundaries and provided early warning of approaching bed boundaries. This system created a complete picture of the layers above, below, and around the sensor. A complete picture improved our understanding of the reservoir's geology and aided us in placing the well in thin sand. It also improved the capability to steer the well through the most productive part of the reservoir while maintaining a desired distance from adjacent formations.

In addition to geosteering and well placement, advanced application algorithms developed for this tool are used to calculate formation resistivity and formation anisotropy, as well as dip and azimuth of formations within and around the reservoir.

This paper describes the planning and execution of the geosteering job done with this new technology. A flowchart of the geosteering workflow is discussed. Formation evaluation and well placement techniques based on this new azimuthal deepreading technology are explained and detailed. Lessons learned, pitfalls to avoid, and best practices and challenges are described in detail. Finally, field examples are included that show the usefulness of this new technology during steering and evaluating the Oseberg field.
"Will My Partners Slow Me Down?" The Effect of Partner Ownership and Experience on Deepwater Project Execution Time
Authors: Sharma Arun K.
Published: September 2008

Executing projects on schedule is particularly important in the Deepwater, where massive capital investment coupled with first oil delays has a pernicious impact on project NPV. Oil companies, nevertheless, routinely farm-out equity in order to reduce investment risk, hoping partners will not increase development timing risk. This paper addresses the implications of partner selection on project execution time, thus providing firms a rigorous foundation of knowledge upon which to formulate partnering and portfolio management strategy.

This study is the result of both qualitative and quantitative analysis. The quantitative analysis is presented here, including the design and confirmative testing of a predictive causal model incorporating empirical deepwater joint venture (JV) field data and structural equation modeling (SEM) methods. The database used in this paper included all Deepwater JVs globally.

A number of findings emerged from the statistical analysis, highlighting the impact of partner selection on project delivery time. I found that neither the number of partners within a JV, nor the operator's equity ownership above a controlling interest had a significant effect on first oil timing. Operator experience, however, had a significant beneficial impact on development time, whereas non-operator experience within the JV had no impact. While non-operators may have limited impact on a JV's development speed, the experience non-operators gain within a JV is critical to their effectiveness as future operators. Remarkably, an operator's past non-operational experience is more beneficial to JV project delivery time than their past operational experience. Thus, the best operators have been (and continue to be) active non-operators. These results suggest that the benefits of a diversified holding of operated and non-operated projects include not only fiscal portfolio risk reduction but also enhanced project management.

This study presents quantitative evidence that portfolio risk reduction through equity diversification (i.e., farm-out strategies) does not reduce project value via revenue delays. Furthermore, this research quantifies the benefits of non-operator ownership. Practitioners may find this research useful to optimize their JV portfolios and develop strategies for partner selection. Governments can use these findings to help construct natural resource development policy (lease sale guidelines).
Reconciling Production and Well-Test Data in Mapping kh Trends: Field Study
Authors: Khasanov Mars , Krasnov Vitaly , Petrov Alexander , Kelkar Mohan , Bahar Asnul
Published: September 2008

During a field development process, one of the parameters used to decide the in fill well locations is permeability-thickness (kh) map. This map can provide us with overall trends in the conductivity of the formation as well as information about optimizing water flood patterns. Rosneft routinely uses kh maps as a reservoir management tool. In addition to developing the well locations, it also uses the kh values to optimize the artificial lift design so that the wells are produced efficiently.

One difficulty typically observed in generating kh maps is a prominent display of "bull's eyes." The values of kh can change dramatically from well to well, which causes problems in interpolation of these values. Some times, because of large discrepancies, the overall patterns are hard to discern and well planning is more difficult.

In the proposed work, we developed a procedure for capturing the trends in kh maps by removing the bull's eyes. The kh values are determined by two methods: use the production data and using simplified procedure, determine the value of kh, or evaluate well test data and determine the kh values. In the first step, we developed a process of reconciling the well test data with the production data by adjusting the kh values and skin factors so that the productivity index can be maintained. In the second step, we assumed that uncertainty exists in determining the true kh value at each well location due to interpretation and resolution of data. Instead of strictly honoring the kh values at each location, using error kriging approach, we recalibrated the kh values so that the new kh maps are smoother and without bull's eyes, and are able to define the overall trends much better. We also ensured that the productivity index matches correctly. Further, by examining the productivity index as a function of time (based on production data), we are able to determine how the skin factor changes as a function of time, which provides valuable information about potential damage at the well location. The procedure was validated by applying it to a large oil field located in Siberia with successful application of in-fill well program.
Stress Reorientation Around Horizontal Wells
Authors: Singh Vasudev , Roussel Nicolas P. , Sharma Mukul M.
Published: September 2008

The production and injection of fluids in a reservoir results in reorientation of stresses. This phenomenon has been supported by field studies and micro-seismic observations. This paper presents a study of stress reorientation around horizontal wells. Stress reorientation has been calculated for different scenarios and patterns of horizontal injection and production wells.

Horizontal wells are increasingly being used for production and waterflooding. Long-term injection into these wells can result in the creation of fractures that grow over time. The effect of fractures on reservoir sweep and on problems such as early water breakthrough is largely controlled by fracture / stress reorientation. A systematic study of stress reorientation around horizontal wells and well patterns will allow an operator to (a) select candidate wells for fracturing (b) choose appropriate operating conditions to avoid early water breakthrough and achieve better reservoir sweep (c) choose the right time window for fracturing (d) improve the design of multiple fractures in single horizontal well.

Poroelastic simulations show that the maximum stress trajectories tend to align along injection wells and across production wells. The extent of stress reorientation varies depending on the injection rates, reservoir pressure, production rates, in-situ stress contrast, distance between wells and orientation of the wells with respect to the in-situ maximum/minimum stress. Some general rules of thumb are derived about stress reorientation around horizontal wells and conditions favoring/opposing the reorientation have been analyzed in detail. Implications for waterflood sweep efficiency are discussed.
Collapse and Burst Test Methods for Sand Screens
Authors: Gillespie George
Published: September 2008

This paper will review the test methods advocated in the draft of the ISO Sand Control Screens (SCS) that is scheduled to go to ballot in 2009.

In early 2004, a task group was formed to develop the initial ISO SCS standard that covers the use of conventional screens in oil/gas wells. A key part of the draft is two test methods developed to determine the performance rating for the collapse or burst resistance of a conventional sand screen assembly. Included in the draft are definitions of product design families, and the scaling methods that can be used.

While the draft was being formed, the service companies have conducted periodic collapse or burst tests to provide performance ratings on specific products. Many of these tests were conducted using the methods outlined in the draft. The test methods are valid approaches to simulate a collapse or burst load that can be applied to a sand screen during well development or production. This paper will present test results of over sixty collapses and burst tests, and will summarize lessons learned about the test methods.

Many applications for oil/gas wells may require high collapse or burst ratings for the screens. Even in seemingly low pressure applications, completion problems many require higher collapse or burst resistance than anticipated, and the screen must not fail or the well could be lost. The ISO SCS draft establishes test methods for conventional sand screens that will provide the operators with reliable ratings for collapse and burst resistance.
Enhanced Characterization of Multi-Phase Downhole Fluid Samples Using a Full Spectrum Weighted Regression Analysis
Authors: Butsch R. J. , Morris C. W. , Pinto K. T.
Published: September 2008

Formation testers are commonly used to obtain fluid samples and measure formation pressure during openhole logging operations. Accurate identification of the produced fluid usually depends on the analysis of the sample chamber contents at the surface. An enhanced fluid characterization technique is now possible using the measurements of in-situ optical fluid density. This multi-phase fluid analysis can be used to determine the type formation fluids and to evaluate significant fluid characteristics.

The optical fluid analysis technique utilizes a visible and near-infrared absorption spectrometer for fluid discrimination. The spectrometer measures the light transmittance of a liquid at many different wavelengths and distinguishes between oil and water by comparing the resulting absorption spectra in the visible and near-infrared region. The spectrometer yields quantitative data on specific fluid phase volumes and qualitative data concerning fluid properties. Experiments were performed to catalog the optical fluid density characteristics of typical hydrocarbons, formation waters, filtrates, drilling mud systems, and mixtures of these fluids.

Utilizing this data base, optical density measurements can do an excellent job differentiating between oil, oil-base mud, and water. Hydrocarbon responses also show a strong correlation trend with optical fluid density measurements and can be used to estimate the in-situ oil gravity. Furthermore, quantitative differentiation between oil-base drilling fluid filtrates and hydrocarbons is possible. This outcome was observed with diesel, synthetic oil, and various other oil-base filtrates.

An enhanced technique has been developed, which performs a weighted regression analysis on the entire optical spectrum, to fully quantify the mud filtrate contamination, water, and formation hydrocarbon mixtures in real time. The advantage of this technique, over utilization of a single wavelength, is the ability to evaluate multi-phase fluids more precisely. Field examples are presented to illustrate the application of the optical density information to the interpretation of formation fluid characteristics. The technique reduces overall sampling time, minimizes sample contamination, improves sample quality, and provides basic characterization of the fluids.
Unlocking Tight Oil: Selective Multi-Stage Fracturing in the Bakken Shale
Authors: Miller Brent , Paneitz John , Yakeley Sean , Evans Kent
Published: September 2008

In recent years, the formation known as the Bakken Shale in eastern Montana and western North Dakota has seen enormous growth in oil and gas production. Scientists from the United States Geological Survey have commented that the area has the potential to become "the next Saudi Arabia."

In most cases, the Bakken horizontal wells are fracture stimulated. However, with several thousand feet of formation, effective stimulation of the entire length has proven time-consuming and costly. In the past, a single-leg zone was fractured all at the same time, regardless of the varied permeability of the layers. Although this simple method of stimulation was seen as a success at the time, a new, more efficient method using swellable packers with reactive elements now promises to optimize total recovery and minimize fracturing cost.

Case history data will show how employing multiple frac sleeves with swellable packers straddling each interval proves to be a cost-effective way to stimulate multiple zones and save days of rig time. Specific experience in the Bakken field provides an optimization model for worldwide well completion markets
Investigating Matrix-Fracture Transfer via a Level Set Method for Drainage and Imbibition
Authors: Prodanovic Maša , Bryant Steven L. , Karpyn Zuleima T.
Published: September 2008

Multiphase flow and transport phenomena within fractures are important because fractures often represent primary flow conduits in otherwise low permeability rock. Flows within the fracture, between the fracture and the adjacent matrix, and through the pore space within the matrix typically happen on different length and time scales. Capturing these scales experimentally is difficult. It is therefore useful to have a computational tool that establishes the exact position and shape of fluid/fluid interfaces in realistic fracture geometries. The level set method is such a tool. Our progressive quasistatic (PQS) algorithm based on the level set method finds detailed, pore-level fluid configurations satisfying the Young-Laplace equation at a series of prescribed capillary pressures. The fluid volumes, contact areas and interface curvatures are readily extracted from the configurations. The method automatically handles topological changes of the fluid volumes as capillary pressure varies. It also accommodates arbitrarily complicated shapes of solid confining surfaces.

Here we apply the PQS method to analytically defined fracture faces and aperture distributions, to geometries of fractures obtained from high-resolution images of real rocks, and to idealized fractures connected to a porous matrix. We also explicitly model a fracture filled with proppant, using a cooperative rearrangement algorithm to construct the proppant bed and the surrounding matrix. We focus on interface movement between matrix and fracture, and snap-off of non-wetting phase into the fracture during imbibition in particular. The configuration of fluids is strongly affected by asperities in unpropped fractures and by the locally open regions at the proppant/matrix interface. The area of phase in contact with the matrix is nonlinear with phase saturation and strongly hysteretic, and thus transfer functions based on saturations should be used with caution. The effect of coupling fracture capillarity and matrix capillarity on multiphase flow properties depends on the relative sizes of typical pore throats in the matrix and typical aperture in the fracture. The simulations agree with direct obsevations of fluid configurations in fractures.
Significant Cost Savings Achieved through the Use of PDC Bits in Compressed Air / Foam Applications
Authors: George Bryan , Grayson Eric , Lays Roger E. , Felderhoff Floyd , Doster Mike , Holmes Matt
Published: September 2008

Polycrystalline diamond compact (PDC) bits are widely regarded as an excellent means to improve penetration rates throughout the world in many fluid drilling applications. However, although attempts to apply PDC technology in air and foam drilling environments have been made in the past, the practice has been largely deemed uneconomical due to excessive damage to the cutting elements. Since the need for significant performance gains persists, an improvement in bit performance can benefit the industry by increasing penetration rates and operating efficiency, thus reducing drilling costs.

Initiatives have been undertaken in a joint effort between an operator and a service company to test modern PDC bit designs in the dry air, nitrogen, and foam drilling applications of the Appalachian Basin in the Eastern United States and of the Permian Basin in West Texas. These are widely drilled basins with well-known lithology and geological properties. The initiatives included identifying target applications and establishing operating practices while determining the economic viability of applying modern PDC bits in these environments. These efforts were determined to achieve drilling cost savings while reducing or eliminating down-hole complications. Careful bit selection, differences in operating parameters, bit performance and dull condition, and impact on borehole quality were monitored. Performance data was accumulated from dozens of bit runs over the life of the projects. This data has indicated that successful PDC bit performance has increased ROP by 300% with a 30% reduction of days-on-well on one application. The second application averaged 40% more hours on bit with reliable results while drilling 30% more distance, saving a trip and one bit. These results demonstrate the tremendous potential to reduce drilling costs with the conversion from roller cone to PDC bits in air-related applications.

This paper details methods, results, and lessons learned from the testing completed and translates those findings into practical techniques. Case study examples are included, with performance data and drilling conditions to support the findings.
Case History of Sequential and Simultaneous Fracturing of the Barnett Shale in Parker County
Authors: Mutalik P N , Gibson Bob
Published: September 2008

Since 2005, Williams Production Gulf Coast Company has drilled over 100 horizontal wells in the Barnett Shale. The Barnett Shale is an unconventional gas reservoir that encompasses a nineteen county area in the Fort Worth Basin. Slick-water fracturing is the primary technique that has been used to hydraulically fracture the wells.

Recently, Williams as well as several operators have tried fracturing two or more adjacent wells simultaneously with the goal of exposing the shale to more pressure and produce a more complex web of fractures, thereby improving the initial rates and reserves. Simultaneous fracturing or simo-frac technique is expensive and requires much more planning, coordination and logistics as well as a larger surface location.

In this paper, the case history of sequential and simultaneous fracturing of four similarly drilled and completed horizontal azimuth wells in Eastern Parker County, is discussed. All the four wells where stimulated with near identical fracture treatments. The sequentially/simultaneously fractured wells resulted in IPs of 3.3 MMscfd to 3.5 MMscfd with 30-day averages ranging from 2.1 MMscfd to 2.9 MMscfd. The 4th well was a single offset horizontal well drilled with effective lateral 2400 ft less than a quarter mile to the north but had significantly lower IP of 2.3 MMscfd and 30-day average production of 1.2 MMscfd. The initial comparative test results are very encouraging and indicate a more complex fracture network being created in the vicinity of the sequentially/simultaneously fractured wells, which results in a significantly improved well performance.

Williams continues to evaluate the benefit of simultaneous fracturing and has done more simo-frac jobs in other counties with good results. As in this case history, due to surface and lease constraints, many of the simo-frac jobs are being done in wells that are drilled from the same dual pad and have well spacing of the order of 500 ft to 700 ft. The paper also provides an analysis of the simultaneous fracturing jobs done to date in Parker and Johnson County.
Sectional Student Development Committee: New Ideas on Bridging the Student to Active Membership Gap
Authors: Anchliya A. , Weatherford D. J. , Pongratz R
Published: September 2008

Challenging times are ahead, and students today face a pressing demand to transform into young professionals (YPs) by quickly developing the necessary skill sets. We believe they can meet this demand more easily by retaining their membership in SPE after graduation. One way to ensure that today's students will continue their memberships and their involvement in SPE as they become petroleum industry professionals is to reach the SCs locally through the SPE Sections.We propose that professional Sections fill this gap between SCs and professional membership by introducing Sectional Student Development Committees (SDCs) that could act as bridges between the International SDC and SCs. Formation of a Sectional SDC would allow liaisons to distribute the workload among other members of the committee to help the SCs achieve higher goals and better understand the value of continued participation in the Society.
Dielectric Dispersion: A New Wireline Petrophysical Measurement
Authors: Hizem Mehdi , Budan Henri , Devillé Benoit , Faivre Ollivier , Mossé Laurent , Simon Matthieu
Published: September 2008

Dielectric measurements and interpretation, introduced with great promise in the 1980s, have not found widespread use owing to measurement limitations, moderate accuracy, and insufficient quality control. This paper presents a new-generation dielectric tool that overcomes these limitations and brings extra information for more accurate petrophysical formation-evaluation.

One of the revolutionary advances offered by this tool is the continuous measurement of dielectric dispersion (variation of formation dielectric properties as a function of the frequency) at 1-in vertical resolution. The tool uses multi-spacings antenna arrays operating at multiple frequencies in the MHz to GHz range. Moreover, transmitter and receiver antennas have colocated longitudinal and transverse polarizations.

The wealth of recorded data will allow interpreters to both adapt the answer product to the reservoir fluids and geology, and also to provide acquisition quality-controls and error estimates on the results.

Carbonate and heavy oil reservoirs are becoming more and more important. In these two environments, the new tool provides unique answers to better characterize these reservoirs. This tool also addresses traditional dielectric formation-evaluation in fresh water and thinly laminated sands.

Answer products offered by this new tool can be classified in three categories. Pore-fluid analysis from the muti-spacings high frequency measurements•Hydrocarbon residual saturation and invaded zone water salinity•Invasion profile: hydrocarbon saturation profile in heavy oil reservoirMatrix analysis from dielectric dispersion•Carbonates: textural information (Archie m cementation factor)•Shaly sands: high resolution clay volume and anisotropyGeological structure analysis from the muti-polarizations and high resolution•Thin beds analysis•Structural anisotropy measurement in very thin beds•Geological features extraction•Carbonate classification

This paper reviews the dielectric dispersion physics, then describes the tool's architecture, measurements, and data processing chain. Field test examples illustrate the enhanced interpretation potential of dielectric dispersion measurements from this tool.
Acoustic Measurement and Calibration of In Situ Stress Anisotropy Around a Wellbore
Authors: Al-Tahini Ashraf , Abousleiman Younane
Published: September 2008

The acoustic techniques for estimating the in-situ stresses from downhole tools are being validated for sandstone, limestone (including chalk), and shale in an experimental laboratory setup using large cubic samples of each rock type subjected to stress-induced anisotropy. The experiments involve the measurement of: acoustic velocities (compressional and shear wave); radial, axial and transversal strains; and the corresponding displacements around the borehole along directions parallel and perpendicular to the applied stresses. We show that the stress magnitudes measured at the wellbore wall vary considerably depending on the type of rock being tested and thus velocities have to be calibrated according to rock type to take into account the specific rock mechanical properties and their stress anisotropy dependence when stresses are estimated from the compressional and shear wave velocities in and around the borehole. Our experimental results also show that the measured induced tangential compressive stresses at the borehole for the tested rock materials were found to be nonlinearly correlated with the external applied stress at the boundary. As a result, assumptions of a borehole stress concentration factor of 3 based on Kirsch's equations for a uniaxial stress field may under or over estimate the actual induced compressive stresses at the borehole wall in rocks. The applied boundary stress level at which tensile failure and breakouts occur in the borehole is observed to be correlated with the measured tensile strength from Brazilian tests and the uniaxial compressive strength of each tested rock, respectively.
Managing Operational Challenges in the Installation of an Intelligent Well Completion in a Deepwater Environment
Authors: Ajayi Arashi , Pace Shawn , Petrich Bryan , Adejuwon Adeyemi , Agbonaye Cardinal , Erumwunse Courage
Published: September 2008

Intelligent well completion has various applications in the subsea deepwater environment. The benefits from such applications can only be derived when the system is successfully deployed. A successful deployment requires effective interface management of different components of the completion process. Such management include communication, planning and logistics related issues

Deepwater environment posses its own development challenges. These include high development cost, constrains of existing technologies and issues relating to application of new ones. Implementation of intelligent well completion in this environment may result in additional challenges. Therefore, adequate attention must be placed on managing these challenges in order to achieve desired success. This involves identification and management of key operational success factors. These factors, can be classified under three major categories namely, people, process and product.

This paper offers an insight into how the challenges can be managed to achieve a successful project based on the experience obtained from the deployment of 2 zone intelligent well completion systems. The authors focus on major components of the key success factors and provide feasible solutions to managing the challenges. The information provided in the paper could be used to enhance the planning of the deployment of an intelligent well completion program. It can also be used to identify critical success factors for the deployment of intelligent well system.
The Minimum Required Gas-Injection Rate for Liquid Removal in Air/Gas Drilling
Authors: Tabatabaei M. , Ghalambor A. , Guo B.
Published: September 2008

Air/gas drilling is a technology used for increasing rate of penetration in hard formations and reducing fluid damage to low-pressure coal beds for methane production. It has been widely recognized that maintaining adequate air/gas injection rate is vitally important to achieving hole cleaning against both solid and liquid accumulations. However, it is unclear as what constitutes the "adequate" air/gas injection rate for removal of formation liquid influx. It is highly desirable to have a simple and accurate method that can estimate the critical air/gas injection rate required for cleaning formation liquid influx in air/gas drilling.

Based on Guo's minimum kinetic energy theory for liquid removal in gas production wells, an analytical model has been developed for estimating the minimum required air/gas injection rate to remove formation liquid influx in air/gas drilling. We have expanded Guo's model to include the effects of Reynolds number and droplet sphericity on the drag coefficient. The theory indicates that the minimum required air/gas injection rate depends mainly on liquid density, liquid-gas interfacial tension, hole size and depth, and rate of penetration. A calculation procedure has been developed for estimating the minimum required air/gas injection rate to remove a given rate of fluid influx from the formation. Engineering charts have also been generated for predicting liquid-carrying capacity of air/gas that is injected into the borehole at various rates. This paper provides drilling engineers the necessary knowledge and a useful tool for minimizing complications in air/gas drilling operations.