bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Influence of Interfacial Tension on Water/Oil Two-Phase Relative Permeability
Authors: Shen P. , Zhu B. , Li X. -B. , Wu Y. -S. 
Published: December 2007

Abstract
Water-oil relative permeability characterizes two-phase flow and displacement processes, and its functional form is difficult to determine in a particular reservoir study. Adding various chemical agents into the displacing aqueous phase during alkaline-surfactant-polymer combination chemical flooding in oil production significantly changes interfacial tension (o) on water-oil interfaces, and also increases the degree of difficulty in measuring such changes in the laboratory or field. To overcome the limitations of the existing laboratory measurements of relative permeability (which are applicable only for high ranges of interfacial tension [e.g., σ &gt; 10-2 mN/m], we present a comprehensive experimental study of two-phase relative-permeability functions in much lower, more realistic interfacial tension water-oil systems. In particular, we have (1) develop an improved steady-state method of measuring water-oil relative permeability curves; (2) proven that a critical interfacial tension value (σc) exists such that interfacial tension has little impact on relative permeability for σ &gt; σc, while if σ &lt; σc, relative permeabilities to both water and oil phases will increase with decreasing interfacial tension; and (3) shown that a logarithmic relationship exists between water-oil two-phase relative permeability and interfacial tensions. The experimental results reported here and conceptual models proposed here will be useful for feasibility studies, optimal designs, and numerical simulations of different chemical flooding operations in oil reservoirs.
Effective Torque Management of Wytch Farm Extended-Reach Sidetrack Wells
Authors: Robertson N. , Hancock S. , Mota L. 
Published: December 2007

Abstract
Wytch Farm was at the forefront of extended-reach drilling (ERD) during the 1990's. This was achieved through opportunity, innovation, technology and team work. Late life management of the field has now required that cost-effective sidetrack wells be drilled to sweep the remaining oil in place in the offshore part of the field.
As with many ERD developments, one specific challenge associated with the original Wytch Farm wells was the ability to control torque and drag within manageable levels. While drilling the original ERD wells, it was noticed, by chance, that the addition of particular loss circulation material (LCM) had a profound impact on torque and drag. The mechanism by which this was happening was not fully understood at the time, but considered to be a combination of hole cleaning improvements and mechanical friction reduction.
In an attempt to quantify and better understand the friction reducing mechanism, a series of controlled field experiments have been undertaken.
This paper describes the basis for the field experiments, implementation plan, analysis techniques and results. Results correlate the amount of LCM addition with a marked reduction in friction factor. The effectiveness of LCM sweeps for torque and drag reduction is also discussed. Understanding the relationship between LCM addition and torque and drag reduction will offer cost savings during the drilling of more demanding ERD wells. Explanations of the torque and drag reduction mechanism are also discussed in the paper.
Experimental and Stochastic Modeling of Diffusion-Controlled Matrix-Fracture Transfer in Naturally Fractured Reservoirs
Authors: Hatiboglu C. U. , Babadagli T. 
Published: December 2007

Abstract
Co-and counter-current type transfers due to diffusion between matrix and fracture were studied experimentally using 2-D glass-bead models. Mineral oil and kerosene were used as the displaced phase. The model saturated with oil was exposed to pentane diffusion under static conditions (no flow in fracture) to mimic matrix-fracture interaction during gas or liquid solvent injection in naturally fractured reservoirs. Displacement fronts and patterns were analyzed and quantified using fractal techniques to obtain correlations between the fractal properties and displacement type. Displacements resulted in a mixture of diffusion limited aggregation (DLA) and invasion percolation (IP) type patterns mainly depending on the interaction type (co-or counter current), oil type and displacement direction (horizontal and vertical). Conditions yielding different types of displacement patterns were identified.
Finally, a stochastic model simulating the diffusion process was developed using combined and modified IP and DLA algorithms. The experimental observations were matched to the displacement patterns obtained through the stochastic modeling.
High Angle HPHT Wells
Authors: Gjønnes M. , Myhre I. G. 
Published: December 2007

Abstract
The Kristin field is the most extreme HPHT field in Norway with a reservoir pressure of 911 bar and a temperature of 175°C. This gives an equivalent pore pressure of 1.96 sg. With additional safety margin, trip margin and riser margin, it requires mud weight up to 2.07 sg to balance the pore pressure. Combining very high mud weight, high temperature, sub sea operation, gas reservoir and high inclination create a formidable challenge to tools, equipment, procedures and personnel. In October 2004 Kristin finished drilling the first high angle sub sea gas producer in the world under such HPHT conditions. The positive pressure test of the 7" liner marked the successful completion of the drilling phase. The achievement on Kristin introduces a new term in to the oil and gas industry. HAHPHT wells, high angle high pressure high temperature wells. The well R-3 H was drilled 4 m short of 6000 m with an inclination of 75° without any well control incidents. Drilling of the well was completed in 82 days, 2 days ahead of schedule. This paper will highlight some of the challenges and experiences of drilling HAHPHT subsea wells. As this paper is written Kristin has finished drilling of 4 high angle HPHT wells and 2 low angle wells.
Investigation of a Smart Steamflood Pattern to Enhance Production From San Ardo Field, California
Authors: Mamora D. D. , Sandoval J. E. 
Published: December 2007

Abstract
We have investigated the use of a novel smart steamflood pattern in San Ardo field, California to minimize steam override and thus enhance oil production and reduce steam injection costs. The smart steamflood pattern consists of a vertical injector placed at the center of the pattern and a smart horizontal producer placed on each of two (parallel) sides of the pattern. The horizontal section of the producer is fully open initially, but after steam breakthrough only one-third (heel-end) is kept open.
Using an 8-component thermal compositional model, we compared the performance of the smart steamflood pattern (under steam- and steam-propane injection) against the conventional 9-spot inverted pattern in the Lombardi reservoir, San Ardo field. A 16×16×20 Cartesian model was used to represent one-quarter of the typical 10-acre pattern in the field. Main results of our investigation are as follows.
First, under steam injection at 1200 BPDCWE, oil recovery after eight years is significantly higher with the smart steamflood pattern (61% OOIP) compared to that with the conventional steamflood pattern (51% OOIP). Second, when steamflooding follows cyclic steam injection, the smart steamflood pattern recovers 53% OOIP in eight years compared to 46% OOIP with the conventional pattern. Lastly, steam-propane injection accelerates the first oil production peak by 10% and the second by 24% when compared with pure steam injection using the smart steamflood pattern.
A Simple Model for Annular Two-Phase Flow in Wellbores
Authors: Hasan A. R. , Kabir C. S. 
Published: December 2007

Abstract
Annular flow is associated with production from both gas-condensate and geothermal wells. Oil wells also experience it during high-GOR production. The current mechanistic modeling approach entails estimation of film thickness before computing frictional pressure-drop as gas flows past the wavy-liquid film surrounding the pipe wall. This study probes to discern this film thickness and its impact on pressure-drop computation in wellbores producing steam-water, gas-condensate, and gas-oil mixtures.
Computational results show that the most likely value this dimensionless liquid-film thickness is less than 0.06 in annular flow. For such thin-film thickness, the computed friction factor is only slightly higher than that estimated with smooth-channel assumption. When the homogeneous model is used to compute pressure gradient by ignoring the wavy liquid film on frictional pressure-drop, good agreement is achieved with field data and those of a mechanistic model.
Log-Based Pore Volume Compressibility Prediction—A Deepwater GoM Case Study
Authors: Wolfe C. , Russell C. , Luise N. , Chhajlani R. 
Published: December 2007

Abstract
Pore Volume Compressibility (PVC) is one of the most important parameters for proceeding with project sanctioning. An accurate estimation of pore volume compressibility of reservoir rocks is essential for compaction evaluation, reservoir drive determination, reserves estimates, reservoir pressure maintenance, casing collapse analyses, and production forecasting. This information is then used in modeling the reservoir and calculating the economic value of the project. Thus, obtaining credible indications of this value early in the well evaluation process is invaluable. Unfortunately, this data is usually required long before a conventional core can be obtained and mechanical rock properties measured. Furthermore, cores are only available at discrete points along the wellbore requiring the data to be extrapolated to the missing sections.
To accommodate the need for this data early in the project and to circumvent the short comings of core-based information gaps in the wellbore, a cost effective approach that utilizes common wireline data is used to obtain a continuous profile of the pore volume compressibility with depth shortly after wireline logging operations have concluded. The method employs a log-based mechanical property program that simulates triaxial loading to obtain static elastic moduli as well as rock strength. The resulting rock mechanical properties are then converted into their uniaxial strain equivalents and used to determine the pore volume compressibility. The process is repeated for several drawdown stages with the condition that the deformations are contained within elastic limits. This yields the complete reservoir compaction trend as a function of reservoir depletion.
The log-based model was recently validated by comparing with lab-derived results from an offset well in deepwater Gulf of Mexico. The results indicate that the uniaxial pore volume compressibility obtained from the log-based method matches well with the results obtained in the laboratory. This fact suggests that the log-based approach should be utilized with a high degree of confidence to determine the PVC in the absence of core data, insufficient depth coverage of the cores, and/or to validate the core results.
Relative Permeability Characteristics for Supercritical CO2 Displacing Water in a Variety of Potential Sequestration Zones in the Western Canada Sedimentary Basin
Authors: Bennion B. , Bachu S. 
Published: December 2007

Abstract
Sequestration in deep underground formations of large amounts of CO2, captured from large stationary sources, such as power plants, oil upgraders and refineries, is one method that is under consideration for reducing greenhouse gas emissions to the atmosphere in both Canada and United States. In hydrocarbon-producing regions, such as Texas in the United States and Alberta in Canada, CO2 geological sequestration is likely to first occur in depleted or abandoned oil and gas reservoirs. However, in many regions, including oil and gas producing areas, this is insufficient because either the sequestration capacity of oil and gas reservoirs is lower than the amount of CO2 emissions from large stationary sources, or because this capacity is not available until the reservoirs are depleted. Deep saline aquifers provide a very large capacity for CO2 sequestration that is immediately accessible, and they are found in all sedimentary basins in the North American mid-continent. Proper understanding of the relative-permeability character of such systems is essential in ascertaining CO2 injectivity and migration, and in assessing the suitability and safety of prospective CO2 sequestration sites.
This paper reviews the experimental protocol and presents detailed water-CO2 relative permeability data for three sandstone and three carbonate formations in the Wabamun Lake area southwest of Edmonton in Alberta, western Canada, where four major coal-fired power plants which produce large volumes of CO2 are located. These formations are in general representative of the in-situ temperature, pressure, salinity, porosity and intercrystalline permeability characteristics of deep saline aquifers in on-shore North American sedimentary basins. The data will allow detailed numerical simulations of CO2 injection and sequestration processes both at this specific location, and for similar operations planned elsewhere and around the world.
Making Economic Decisions To Mitigate Lost Circulation
Authors: Whitfill D. , Wang H. 
Published: December 2007

Proposal
Well construction optimization involves many decisions during the planning and implementation stages. One of the most difficult decisions during the planning stage—choosing the system and the approach to prevent lost circulation— becomes even more difficult during the actual drilling operation due to the "heat of battle" environment. What is generally understood is that lost circulation will be one of the major trouble costs during well construction.
In the past, a favored system or approach may have been used for most or all lost circulation incidents. However, improvements in understanding all aspects of lost circulation show that the "favored system" method is technically unwise today in view of logging-while-drilling (LWD) data and other recently developed sources of information. The delineation of fracture geometry induced during drilling, based on rock properties, may point out significant differences in the length and width and seriousness of anticipated induced fractures. Major differences in permeability between shale, sandstone and vugular limestone also show immediately that one-size-fits-all solutions are not going to be effective or efficient. These kinds of potential information need to be incorporated into any plan for controlling lost circulation.
This paper discusses models and tools to evaluate differences in the resistance of the borehole to lost circulation and also discusses the rationale for choosing a particular approach to a potential lost circulation problem. The rationale for preventative measures is also explored, along with a method to make an economic decision whether to stop drilling and treat for lost circulation or to keep drilling.
Mapping Preferential Flow in a West Texas Waterflood Using Surface Tiltmeters
Authors: Kramm R. C. , Griffin L. G. , Apruzzese J. , Stanley G. R. , Flaten D. W. , Bradshaw M. K. , Lucas B. C. 
Published: December 2007

Abstract
Surface Tilt Mapping (STM) has been successfully applied to stimulation treatments, disposal projects and in numerous steam floods to provide information on fluid movements in the reservoir. This proven technology has now been applied to a waterflood in the San Andres formation at a depth of 5600 feet to analyze preferential flow. Since typical water injection rates in the San Andres range from 100 to 300 BWPD, a novel flowback method was developed to maximize the STM response when testing injection wells under normal operating conditions. An analysis technique that allows the removal of earth tides was also applied to further enhance the quality of the data. The STM results showed conclusive preferential flow direction in the seven wells tested. In most wells, multiple tests were performed with good agreement on the flow trend.
Hierarchical Simulation of Multiple-Facies Reservoirs Using Multiple-Point Geostatistics
Authors: Maharaja A. , Journel A. 
Published: December 2007

Abstract
In reservoirs with more than three facies, a better and more geologically sound approach is to hierarchically simulate the reservoir facies. Ideally, the hierarchy should follow the sequence of deposition of the facies in the reservoir. Three alternative hierarchical approaches that honor depositional relations are applied to a synthetic fluvial reservoir consisting of four facies namely, channels, levees, crevasse splays and floodbasin. A 3D example with channel, point bar, levee and floodbasin is also presented. The results using hierarchical simulation are found to be better than those using joint simulation in terms of reproduction of large-scale structures which control flow through the reservoir.
A Semianalytical Method To Calculate Relative Permeability From Resistivity Well Logs
Authors: Li K. 
Published: December 2007

Abstract
A semianalytical model was developed to infer relative permeability from resistivity data. Although it would still be necessary to conduct experimental measurements of resistivity, these are easier than measuring capillary pressure. On the other hand, resistivity data are commonly available from routine well logging. The semianalytical model was tested against experimental data. The results demonstrated that the relative permeabilities calculated from resistivity data were close to those calculated from capillary pressure data. The model developed in this study may also provide an approach to estimate permeability using both the resistivity well logging and well testing.
ESP Model Implementation and Result Analysis Under Gas/Liquid Flow Conditions
Authors: Sun D. , Prado M. 
Published: December 2007

Abstract
The one-dimensional model proposed by Sun and Prado [1, 2] to predict Electrical Submersible Pumps (ESP) head performance under gas-liquid flow conditions has been improved with a new correlation for the ratio of the drag coefficient (Cd) to an interfacial characteristic length ( rinterfacial ). This study has found the ratio, Cd / rinterfacial, is also a function of channel rotational speed in addition to gas void fraction and other parameters. The paper summarizes the model with detailed wall frictional equations and addresses its implementation procedure from a manufacturer's available single-phase catalog data to the predicted two-phase head performance results. The implemented algorithm is especially effective to obtain the ESP head performance under two-phase flow conditions. The study is beneficial for the appropriate design, simulation, and troubleshooting of ESP installations in a two-phase environment.
The model has been used to compute results and perform sensitivity analysis under different two-phase flow conditions: pump intake pressure, gas void fraction, gas flow rates, rotational speeds, Cd / rinterfacial, and wall friction effects, respectively. The sensitivity analysis has been used to determine the correlation for the ratio of Cd / rinterfacial during model development.
The comparison of the model results against the experimental data, except at a low gas void fraction with a low liquid flow rate, shows good agreement. The new model gives an excellent prediction for different shaft rotational speeds compared to Zapata's partial gas-liquid data of ESP [3]. However, further validation with more experimental data is needed.
Microseismic Fracture Mapping Optimizes Development of Low-Permeability Sands of the Williams Fork Formation in the Piceance Basin
Authors: Wolhart S. L. , Odegard C. E. , Warpinski N. R. , Waltman C. K. , Machovoe S. R. 
Published: December 2007

Abstract
Williams Production Company performed a study to improve hydraulic fracturing and field development in the Williams Fork Formation, Piceance Basin, Colorado. The Williams Fork Formation is part of the Mesaverde Group and consists of massively stacked low permeability sandstones. Wells in the Williams Fork are usually stimulated in multiple fracture stages using limited entry techniques. This paper describes how hydraulic fracture mapping was performed with microseismic imaging on two wells in the Grand Valley Field and two wells in the Rulison Field. This was part of a pilot project to assess well downspacing and to assist with stimulation optimization. Fracture length was longer than expected but varied somewhat by field, well and treatment type. Payzone coverage was good considering significant differences exist in breakdown and pore pressures of the various sands within the hydraulic fracture stage. Fracture initiation and early growth did not fully correlate with pore pressure and ISIP data from diagnostic injections but overall payzone coverage generally matched this data.
Environmental Biodegradation and Drilling Performance of Water-based Polyampholyte Drilling Fluid
Authors: Wysocki S. , Bielewicz D. , Knez D. 
Published: December 2007

Abstract
Some of drilling fluids are a mixture of many components including organic as well as inorganic polymers. In order to assure stable parameters and the required technological parameters of drilling fluids, all components must be resistant to downhole conditions. At the same time it would be beneficial if the drilling fluids were biodegradable after the drilling process. As such they would have less of an environmental impact and would be easier to utilize. Organic polymer-based drilling fluids are efficient and environmentally-acceptable, but sensitive to biodegradation so they are treated with biocides. The treatment adds toxicity and makes the waste fluid difficult to dispose off [1]. The challenge in polymer fluid fomulation is to reduce biodegradation of active (while drilling) fluid and increase biodegradation of the waste fliud. Presented in this paper is a study of drilling properties and environmental performance of fluid based on newly synthesized ampholyte polymer.
Drilling performance of the new fluid was evaluated with regard to rheology, filtration, salt and temperature resistance. Samples of the fluid were tested using API Standard Methods.
Environmental study addressed the fluid biodegradation. Biodegradability was investigated using Merck method. The Merck method uses testers with agar surfaces. The bacterial count/ml of the sample is determined by comparing the density of the colonies appearing on the slide with densities shown on the model chart.
The results were compared to results for fluids with starch agents.
The results show that polyampholytic-starch fluid is biodegradable by bacteria but still has good and stable rheological parameters and filtration.
The findings show the advantages of polyampholytes and drilling fluid with polyampholyte components and provide some perspectives for industrial implementation.