bluuebunny/crossref_metadata_2025_split huggingface dataset:
Enhanced Completion Techniques in Naturally Fractured Carbonates in Southern Mexico
Authors: Bailey Jeffrey R. , Perez Jesus , Ritter Wes 
Published: December 2007

Abstract
Integrating the practices of locating, selecting, and acidizing fractures into one focused approach has provided successful results in wells in southern Mexico. Previously these methods handled independently have yielded unpredictable results.
The standard methods of locating fractures within a naturally fractured carbonate do not inherently help in determining which are the important fractures in the geological system. Neither do they indicate which fractures are actually open at a useful distance beyond the borehole wall and will be the main production contributors. Often the drilling processes make both minor and major fractures appear to have equal importance.
In southern Mexico, this network of fractures requires a combination approach to evaluate the candidates. This paper explains how combinations of deeper investigating NMR response, conventional logs, and image logs can be combined to narrow the selection of key fractures. Focusing the subsequent completions on specific fractures allow more investment in actual productive intervals making the stimulation more effective.
Concentrating on the properties of the fractures rather than the host rock enhances the stimulation with the new acid systems available. Focusing on the fractures that will take most of the acid during a stimulation job allows decisions to be made about perforation planning with respect to the other reservoir properties. Perforating decisions and or acid stimulation planning can be used to enhance the fractures not normally sufficiently stimulated. This also allows the decision criteria for perforating to be based around enhancement and final production. Case histories, exclusively from Mexico, demonstrating this technique will be presented, as well as examples of other practices and the results.
Development of the Submerged Arc-Welding Process To Reach High Energy at Low Temperature in the Longitudinal Weld Seam of Line Pipe Used for Gas Distribution
Authors: Barbosa Carlos Henrique , Cavalheiro Benedito Carlos , Ferreira Sérgio Ricardo P. 
Published: December 2007

Abstract
Toughness on the welded joint, in special on the heat affected zone, is one of the most difficult requirements to be complied, when it is necessary to weld thick carbon steel pipes, with wall thickness over than 16 mm. Basically, it is defined by the final microstructure. In the weld metal it is the result of the combination between the hardenability and the cooling thermal cycle, related with welding heat input. In the area around the weld bead, called heat affected zone, it is the result of the welding heat input action on the base metal. It is possible to get a better microstructure in the heat affected zone, more suitable to toughness requirement, if heat input is decreased. Considering the weld metal, there is an appropriate range of heat input, which results in better toughness behavior. In order to get appropriate heat input for thick pipe welding, it was developed the submerged arc process with 4-wire tandem technique for pipe welding and the development benefits are shown on this paper.
Stress-Sensitive Fracture-Flow Modelling in Fractured Reservoirs
Authors: Jolly R. J. H. , Wei L. , Pine R. J. 
Published: December 2007

Abstract
The flow characteristics of fractures are significantly affected by the stresses acting upon them. Reservoirs where the majority of the fluid flow is through fractures are very sensitive to the stress regime and its perturbations. Activities, such as production from a reservoir or injection into a reservoir, cause changes in the fluid pressure. This will alter the effective stress, which in turn will affect the flow of hydrocarbons through the fracture network. In order to understand how hydrocarbons flow within a fractured reservoir it is necessary to determine the influence of both stress and fluid pressure in a fracture network.
There have been many experimental studies showing the influence of stress on the flow of fluid through single fractures from which a relationship between fracture permeability and effective stress can be developed. Effective stress acting on a fracture can be established by considering the orientation of the fracture relative to the in-situ stress regime and the fluid pressure within the fracture. Once the effective stress acting on a fracture has been found the corresponding permeability can be assigned within a discrete fracture network (DFN) model. This approach then allows examination of stress-sensitive flow within fractured reservoirs.
This paper presents a methodology for incorporating in-situ stresses and stress changes due to production and injection in DFN modelling. The approach is significantly different from published methodologies on this subject, which are based on continuum porous medium modelling. By simulating and interpreting well tests in the fracture network during reservoir appraisal and after significant production, the presented approach would help in determining the influence of stress on hydrocarbon flow within a fracture network and to optimise future well locations and orientations.
Coupling Fluid-Flow and Geomechanics in Dual-Porosity Modeling of Naturally Fractured Reservoirs – Model Description and Comparison
Authors: Chen Her-Yuan , Teufel Lawrence W. 
Published: December 2007

Abstract
The objective of this paper are: (i) to summarize a recently developed coupled fluid-flow/geomechancs, dual-porosity model intended to describe the behavior of naturally fractured reservoirs, and (ii) to analyze and compare four other existing models. Conceptual consistency is examined for each model within the concept of dual-porosity. The comparison provides important understanding and interpretation to the complex model parameters.
Relative Permabilities of Gas-Condensate Fluids in Heterogeneous Porous Media
Authors: Moctezuma-Berthier A. , Samaniego F. V. 
Published: December 2007

Abstract
Reservoir cores have complex porous structure and conventional approach to characterize two phase flows in the laboratory can be inadequate, especially in presence of fractured or vuggy porous media. An important problem is the determination of the relative permeabilities to the interpretation of two phase flow experiments. The relative permeability analysis for gas and condensate fluids presents special interest due to changes in fluids properties, like interfacial tension and viscosity due to compositional changes. In this way, relative permeability curves depend on the capillary number; thus the experimental conditions for the fluids and porous media must be carefully analyzed in order to get representative reservoir conditions.
This work presents a methodology for the realization of laboratory representative studies of flow in heterogeneous cores flowing with gas and condensate equivalents fluids. The relative permeability curves are found fitting the oil production and pressure drop experimental data with a compositional simulator. This simulator was used to have a detailed behavior of the fluids during the experiment.
Selection of the equivalent fluids was made plotting the derivative of the capillary number with respect to pressure vs. capillary number. We analyzed the curve for different mixtures and results compared with the reservoirs fluids curve. With this analysis, we got a pressure interval for the experiment and the required composition, the required to prepare a mixture which capillary number behavior was like reservoir fluids.
In order to reproduce the detailed petrophysical model of the sample, the longitudinal porosity distribution was gotten from X-ray computerized tomography. In addition, the petrophysical porosity and effective permeability behavior of the sample for different confining pressures was done.
This methodology was applied to fluids and samples from a carbonate fractured gas and condensate reservoir from Gulf of Mexico. It was possible to get the relative permeability curves using a binary mixture of C1-C10 in a specific range of pressure, where the capillary number for both real and mixture was quite similar. The match between laboratory and simulation results was very good.
Adjustable Rate Drilling Contracts - Go With the Flow?
Authors: Moomjian Cary A. 
Published: December 2007

Abstract
This paper reviews adjustable rate drilling contracts from philosophical and practical perspectives and discusses various means of structuring contractual provisions which adjust dayrates to reflect published rig rates, commodity (oil or gas) prices, an index or other designated measuring device. The analysis considers selection of an appropriate driver for rate adjustments, frequency of rate adjustments, use of a rate "floor" and "ceiling", and associated issues. The discussion reviews the attributes and drawbacks of adjustable rate drilling contracts, considers potential drivers for rate adjustments and evaluates hypothetical applications.
New Technology in Diamond Drill Bits Improves Performance in Variable Formations
Authors: Beaton Tim , Johnson Keith 
Published: December 2007

Abstract
Recent advances in diamond bit technology have helped to bridge the gap between polycrystalline diamond compact (PDC) and diamond impregnated bit applications. A new type of diamond bit has been developed to effectively drill hard, abrasive formations, while retaining the ability to efficiently drill through non-abrasive sections. This new type of diamond bit utilizes a three part cutting structure consisting of PDC cutters, diamond impregnated blades, and hot pressed diamond impregnated inserts.
Technological advances in the design and manufacture of diamond bits have greatly expanded the applications of both PDC and diamond impregnated bits. However, there are still many intervals of hard rock drilling which have sections that are too hard or abrasive for a conventional PDC bit, but also contain sections that are not sufficiently abrasive to be effectively drilled with a conventional diamond impregnated bit. Drilling these types of intervals with conventional drill bits has proven very costly. Operators have been forced to choose between incurring expensive trip times, due to the need to frequently change out bits to maximize the rate of penetration (ROP) in the different formations, or suffering through the very slow penetration rates typical of conventional impregnated drilling in non-abrasive formations.
A very successful run has recently been completed with this new diamond bit in the Huamampampa formation in Tarija, Bolivia. In a long, 8 ½" hole size section, where the shale content ranged from 10 to 90%, this new bit type drilled to TD with a higher overall rate of penetration than any offset. The combination of PDC cutters with hot pressed diamond impregnated inserts in a diamond impregnated matrix has proven to be a very versatile cutting structure in variable formations.
Optimization of Stress-Relief Grooves for Rotary Shoulder Connections
Authors: Hommel Mark 
Published: December 2007

Abstract
Field experience and finite element studies have established the effectiveness of utilizing a stress relief groove on the pin of a threaded connection to prolong its life. Nevertheless, the exact design geometry of the stress relief groove is subject to discussion and even controversy. Moreover, the need to recut damaged threads on extant tools motivates the minimization of stress relief groove width so that subsequent machining will not be precluded.
The purpose of this paper is to present some finite element results which examine the dependency of stress on stress relief groove width and thread runout.
A parameterized finite element model of a 5-1/2 F.H. threaded connection has been developed which allows the variation of the width of the stress relief groove. Stresses are computed for a variety of widths. It is found that an optimal width does in fact exist. Widths shorter than optimum simply introduce further stress concentrations due to the presence of unnecessary pin threads, while stress relief grooves with a larger width than optimum tend to load up the remaining threads excessively.
An unexpected result of this study is that the finite element results are strongly dependent on thread runout. This is not a factor for stress relief goove widths greater than approximately 1 inch. But for shorter widths, box thread runout is a factor because the partial box thread which engages the apparent last engaged thread of the pin causes a lower stress to be set up in the pin, compared with what it would be if a full thread were engaging the pin. In other words, thread runout works in the operator's favor in applying a more gradual load to the pin threads compared to what it would be in the absence of runout.
From this it is concluded that a re-examination of tolerances on stress relief groove width and also box counterbore depth is needed.
Development of OCTG Connection for Automated Drilling Rigs
Authors: Maruyama K. , Tsuru E. , Wada Y. , Tsukano Y. 
Published: December 2007

Abstract
Automated drilling technology in offshore rigs is becoming increasingly important. It provides for safer working environments and increased efficiency. New tubular handling equipment and remote controlled power tongs are integral components of the new automated rigs. Connection manufacturers have to develop new products that are compatible with the new technology.
In the conventional tapered connection it is possible to wedge the threads crest to crest, commonly resulting in a "galled" connection making it unusable. When manual tongs are used, the human operator is more responsive to this condition and takes corrective action prior to connection damage. With automated tongs, when this condition occurs, it is less likely to be recognized and reacted to before substantial damage has occurred.
This paper describes the research data of a newly developed tapered connection design. The design is capable of being assembled quickly and easily with the characteristics of simple easy stabbing and high galling resistance. The development incorporates a unique thread profile that is distinctly different from current OCTG thread forms. The new thread form may be applied to other connections that use the API Buttress type thread form.
Reeled Pipe Technology for Deepwater Drilling Utilizing a Dual Gradient Mud System
Authors: Fontana P. , Sjoberg G. 
Published: December 2007

Abstract
The search for hydrocarbons is constantly moving into deeper and deeper waters. This introduces new challenges to the drilling industry as production demands requires that large, high volume completions are placed in these wells. In addition, narrow pore pressure and fracture pressure margins increase the number and subsequently size of casings to be set.
The use of a "Dual Gradient" drilling system provides an answer to these challenges.
The use of large diameter "Reeled Pipe" further facilitates the dual gradient drilling process.
The DeepVision project has developed and tested several critical components of such a system. The system includes a subsea centrifugal pump system, large diameter reeled pipe up to 5.5", bottom hole assembly components, and a new injector head concept for the reeled pipe. The project is ready to be advanced into prototype field testing and commercialization.
Denver Unit Infill Drilling and Pattern Reconfiguration Program
Authors: Thai B. N. , Hsu C. F. , Bergersen B. M. , Albrecht S. L. , Richardson T. W. 
Published: December 2007

Abstract
The Denver Unit CO2 flood, one of the largest in the world, was implemented in 1984. CO2 injection was subsequently expanded in 1989 and again in 1991. By 1994, this 10 year old CO2 flood had a well-established decline in its production function. Through infill drilling and pattern conversion, the mature CO2 flood in the Denver Unit was revived. The redevelopment program depended heavily on the reservoir simulation technology and the multi-discipline team concept to ensure its technical and economical success. Thus far, the redevelopment program has added approximately 6600 barrels of oil per day to the existing production at peak rate, and approximately 14.2 million barrels of oil to the ultimate reserves. This report reviews the infill drilling and pattern reconfiguration simulation studies, the pilot program, which led to full field development, and the results of the project to date.
A New Technique to Determine Porosity and Deep Resistivity from Old Gamma Ray and Neutron Count Logs
Authors: Wo S. , Weiss W. W. , Balch R. S. , Scott L. R. , Kendall R. P. 
Published: December 2007

Abstract
Multivariate correlations developed via radial-basis function (RBF) network analysis of a modern suite of logs are used to estimate crossplot density-neutron porosity and pseudo-deep resistivity from 1950's vintage well logs. Historically, porosity has been estimated with the logarithm of the neutron count rate standardized with a 2% porosity tight spot and a maximum porosity of ~40% in a shale stringer. Despite a frequently observed visual correlation of the gamma ray track with the neutron count rate, the gamma ray log information is not included in conventional porosity estimates.
The visual comparison of the openhole gamma ray and the neutron porosity to the shape of the crossplot porosity from a new well, Foster 4, is similar to the pattern seen between the old gamma ray and the neutron-count rate logs. The new log data were investigated with various RBF networks to correlate the gamma ray and neutron-count rate with the crossplot porosity. An optimal RBF network was then used to estimate the crossplot porosity of the Penrose sand for 22 wells in the Reed Sanderson Unit where only cased-hole gamma ray and neutron-count rate logs are available. An equation converts the modern neutron log to the old style neutron count rate while providing a normalized input to the network training. The "goodness" of the RBF network predictions was validated via exclusion testing.
A similar procedure was used to estimate a pseudo-deep resistivity in old wells. The study indicated that a carefully trained RBF network could identify the high resistivity intervals (shale stringers) with only gamma ray and neutron count rate used as the network inputs. The methodology presented should prove useful to others faced with characterizing old fields.
Time-to-Depth Conversion of Nash Draw "L" Seismic Horizon using Seismic Attributes and Neural Networks
Authors: Hart D. M. , Balch R. S. , Weiss W. W. , Wo S. 
Published: December 2007

Abstract
Well log and 3-D seismic data were used to construct three depth maps for the top of the target L horizon of the Nash Draw field in southeastern New Mexico. The first two depth maps were made using Landmark° software packages TDQ and Z-map. The third depth map was made using a multilayer perceptron (MLP) neural network to regress for velocity at each seismic bin. At Nash Draw the wells are confined to the central region of the seismic survey, and conventional geostatistics reliably interpolated depths only in the region defined by well control. The MLP approach used the best three of 28 statistically ranked seismic attributes to predict the average velocity field from the surface to the L horizon. Each map was constructed using 15 wells as control points with three wells excluded for testing. Test wells one and two were located away from the control wells and have anomalous average velocities/depths.
Accurate depth maps are useful for reservoir development, particularly for stratigraphic and structural trap location, drilling depth and reservoir modeling.
The three test wells were used to compare the robustness of the computed depth maps, and all depth predictions were compared to the true depths determined from gamma ray logs for each well. TDQ, Z-map and MLP predicted values within 229.4, 104.7 and 7.6 feet, respectively, at test-well-1; 129.4, 47.7 and 43.7 feet, respectively, at test-well-2; and 12.4, 4.1 and 16.5 feet, respectively, for test-well-3.
Geostatistical methods underestimate the depths to the top of the L for the test wells lying outside the central clustering of control wells, while the MLP solution calculates a relationship that should be valid in each seismic bin in the field. Further refinements in the data and improved methodology are expected to yield a higher degree of accuracy between the real and predicted depths using MLP.
Iterative Method To Determine Gas Reserves Using Material Balance and Pressure Transient Analysis
Authors: Sehbi Baljit S. , Frailey Scott M. , Lawal Akanni S. 
Published: December 2007

Abstract
The p/z vs. Gp material balance approach is an established, simple, quick and convenient means of surveying a reservoir's performance and determining gas reserves and gas-in-place (G). The x-intercept is G. Unfortunately, this approach may be an independent analysis, and not confirmed with a separate method.
Theory requires that the "p" in the p/z term to be the average reservoir pressure at which a cumulative production of Gp occurs. A source of average reservoir pressure is a pressure buildup test in which the MBH method is used to find average reservoir pressure. The MBH method requires an estimate of drainage area (A), which is directly related to G (∞Ah); this is termed GMBH. The average reservoir pressure that was calculated using the estimated A are plotted as p/z in the material balance plot. An extrapolation of the trend to the x-axis is Gp/z. The GMBH and Gp/z are used iteratively until the two estimates of G converge.
This proposed method is tested on synthetically derived pressure data simulated with a commercially available, analytical well testing program for two different reservoir shapes and three different well locations. One single-well gas reservoir is analyzed for the case study.
New Dual-Probe Wireline Formation Testing and Sampling Tool Enables Real-Time Permeability and Anisotropy Measurements
Authors: Proett Mark A. , Chin Wilson C. , Manohar Mohan , Gilbert Gregory N. , Monroe Myrick L. 
Published: December 2007

Abstract
A recently introduced wireline formation-testing tool incorporates new digital control technology to significantly improve formation pressure testing and fluid sampling. Closely spaced dual probes are simultaneously deployed for pressure testing and fluid sampling. Besides increasing tool reliability through redundancy, the two probes allow for advanced pressure-testing techniques. For example, formation anisotropy can be determined with an interference test between the two probes. Alternatively, a new pressure-pulsing technique can be used, which uses time delays between the probes’ measured pressures to determine additional hydraulic diffusive properties of the formation. The drawdowns can be rate- or pressure-controlled from either probe, making it suitable for pressure testing in very low to high permeability formations (0.001 to 1000 md).
A primary focus of the new technology is improving the quality of reservoir fluid samples. An innovative pump-out design using a digital control feedback system enables the tester to continuously monitor the fluid sampled and to make precise adjustments to the rate and pressure at which the fluid is withdrawn from the formation and injected into a sample chamber. Because the tool design incorporates a powerful pumping-system motor and an efficient hydraulic system, invaded fluids surrounding the probes, such as mud filtrate, can be flushed 50% faster than other wireline test tools, thereby enabling quicker sampling of virgin formation fluids. Sample chambers can be filled against hydrostatic pressure to ensure pressure-volume-temperature (PVT) quality samples, and additional pressure can be applied to minimize phase changes that might otherwise occur because of temperature gradients in the borehole. The new system can also be used to perform a closed-chamber PVT test for the bubble point of the fluid sampled.
This paper details operational features of the new tester and introduces new pressure-testing and sampling interpretation techniques. Field-test results are used to demonstrate these features and techniques.