bluuebunny/crossref_metadata_2025_split huggingface dataset:
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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.