bluuebunny/crossref_metadata_2025_split huggingface dataset:
Advanced Multizone Stimulation Technology
Authors: Lonnes S. B. , Nygaard K. J. , Sorem W. A. , Hall T. J. , Tolman R. C. 
Published: December 2007

Abstract
ExxonMobil has developed two novel reservoir stimulation technologies that enable the rapid delivery of numerous high-quality stimulation treatments within a single cased wellbore. These technologies were developed for the purpose of improving, or enabling, economic hydrocarbon recovery from formations that contain multiple stacked reservoir intervals or require the stimulation of long productive intervals. These technologies:(1) enable the stimulation of multiple target zones via a single deployment of downhole equipment; (2) enable selective placement of each stimulation treatment so that they may be designed specifically for each individual zone to maximize well productivity; (3) provide positive isolation between zones to ensure each zone is treated per design and previously treated zones are not inadvertently damaged; and (4) allow for treatments to be pumped at high flow rates to facilitate efficient and effective stimulation.
Enhancing Collaboration Between Engineering and Operations—A Case Study of Alaska Work Processes
Authors: Anders J. , Cooper K. , Dube A. , Green P. 
Published: December 2007

Abstract
This paper details the collaboration and well information system BP Exploration (Alaska), Inc. has implemented to enhance communication and data sharing between work groups operating the Prudhoe Bay field. Accessing and sharing well information and maintaining quality communication between geographically separate Operations and Engineering teams is an issue in all oilfield operations. Using web-based interfaces and database stores has allowed BP Alaska to efficiently operate on the North Slope.
Simulation of Physical-Chemical Processes During Carbon Dioxide Sequestration in Geological Structures
Authors: Calabrese M. , Masserano F. , Blunt M. J. 
Published: December 2007

AbstractUnderground storage of carbon dioxide, CO2, is one way to reduce atmospheric releases of greenhouse gases. The sequestration of CO2 in a depleted gas reservoir is simulated, incorporating molecular diffusion between CO2 and the natural gas, dispersion, dissolution of CO2 in water, and chemical reactions of the CO2 with the aqueous phase and host rock.This study is applied to a depleted gas reservoir located in the North of Italy. Since the end of production the field has been used for gas storage, and in this work it has been considered for a pilot project of CO2 injection. The different physical and chemical phenomena acting in the reservoir are simulated to investigate their influence on the total storage capacity. The effect of injection rate, the point of injection and the purity of the injection fluid are analyzed.While molecular diffusion of CO2 in methane can be neglected, the dissolution of CO2 in water increases the maximum storage capacity. Both the pattern of reservoir heterogeneity and the degree of mechanical dispersion has a notable impact on the results. Particular attention should be given to the composition of the injection fluid, because the presence of impurities strongly affects the total stored mass.Low injection rates give a larger total stored mass, since gravitational forces act to transport the CO2 to the top of the aquifer, but only after long periods of injection. Near the gas/water contact, the residual gas saturation has a significant impact on storage.Precipitation reactions render the CO2 immobile in a solid phase, but over a very long timescale.
Perforating for Zero Skin: A Study of Productivity Improvement in Ecuador
Authors: Flores J. G. 
Published: December 2007

AbstractThe most significant components in the skin equation that do not depend on nature are invasion damage and perforating-induced damage. The oil industry has approached the invasion issue by using stimulation treatments intended to regain the permeability lost through formation damage, or by deep-penetration perforating aimed at bypassing the invasion damage. Perforating is known to create a low-permeability crushed zone in the formation around the perforating tunnels that also constitutes a flow restriction, which can impair the well's productivity or injectivity. A perforating design that guarantees bypassing the invasion and at the same time eliminates the perforating tunnel damage is crucial in obtaining a zero-skin completion and maximum productivity or injectivity.This paper introduces an objective methodology to design perforating jobs for zero-skin and maximum productivity. The method is based on theoretical development and experimental studies carried out on cores from three fields in Ecuador's Oriente basin. Simulations using experimental data allowed for modeling the performance of the perforating charges and for determining accurate values for the penetration depth in the actual reservoir rock. The depth of invasion for each of the reservoirs of interest was obtained from modern logs in the case of new wells, or from a statistical study based on pressure transient tests in the case of old completions. By coupling the actual penetration depth of the charges with the radius of invasion, objectively designing perforating jobs to bypass the invasion damage became a reality.Solving the second part of the problem involved finding a way to produce clean perforating tunnels. Recent research work has shown that fluctuations in wellbore pressure during the first milliseconds after guns fire actually govern the cleanup of the perforating tunnels and not the initial static underbalance, as originally thought. A perforating job that bypasses invasion, combined with a new design that guarantees a dynamic underbalance at all times, has produced outstanding results in over 40 perforating jobs in Ecuador. Historical field data for conventional underbalance perforating in comparable wells show average skin values of +13 vs. -0.5 using the proposed methodology, with typical production level gains of 300 to 400 BOPD.
Benchmarking Deep Drilling Technologies
Authors: Lambert S. W. , Rogers J. D. , Williamson J. R. , Boyer C. M. , Frantz J. H. 
Published: December 2007

Abstract
The U.S. Department of Energy (DOE) has undertaken a baseline study designed to provide current drilling technology and cost bench-marks as reference points in evaluating future cost improvements to be derived from technology advancements.
Deep formations are one of the sources of natural gas that will play an important role in meeting the growing need for natural gas in the U.S. The Energy Information Agency estimated that 7 % of U.S. gas production came from deep formations in 1999. This contribution is expected to increase to 14 % by 2010.
A deep-well database has been completed that categorizes wells by total depth, targeted formation, geographic location, completion technique, and operator. In addition, information was gathered from operators and service companies reporting the current status and future directions of drilling technologies, which was then compiled into a condensed format.
Bit and downhole motor and turbine technology have improved significantly over the past several years, leading to faster rates-of-penetration (ROP) for deep wells. Polycrystalline diamond compact (PDC) bit technology is one of the most significant technology improvements in the drilling industry over the last 20 years.
Current and proposed well-construction methodologies that should continue to reduce costs of drilling deep and extended-reach wells include solid expandable tubulars and the concept of casing drilling or liner drilling. However, these concepts are still evolving.
As these and other new technologies are applied, the results of this benchmarking effort provide the basis upon which future relative progress and cost savings can be identified and measured.
Analysis of LWD Propagation Resistivity Data in Anisotropic, Thinly-Bedded Formations Identifies Significantly More Hydrocarbons
Authors: Boonen P. , Haugland S. M. , Laughlin D. G. 
Published: December 2007

Abstract
Thinly laminated pay zones are often anisotropic. The horizontal resistivity is dominated by relatively conductive shale layers, and the vertical resistivity is dominated by relatively resistive hydrocarbon strata.When the relative inclination is low, conventional induction and Logging-WhilWhile-Drilling (LWD) propagation resistivity tools only sense the horizontal resistivity and triaxial wireline measurements can be used to estimate the vertical resistivity. However, the relative inclination is often high enough to enable accurate determination of the vertical resistivity from the LWD propagation resistivity data and estimates of the structural dips. The vertical resistivity values can then be used to improve identification and quantification of productive intervals. Cases discussed in this paper demonstrate the modeling software for determining these anisotropy parameters, even in thinly bedded sequences. In practice, the results can be determined rapidly enough to affect completion decisions.
A data processing procedure involving anisotropy analysis, thin-bed modeling, and shaly-sand analysis is described in the context of examples wells which penetrate thinly laminated anisotropic beds.After the modeling exercise, it was evident that the vertical resistivity was significantly higher than indicated on any of the raw resistivity curves. Two shaly sand analyses were performed, the first using the raw resistivity curves, and the second using the modeled resistivity values. A comparison of the results from both shaly sand analyses showed that significantly more hydrocarbons were identified after the modeling was done.
Slimhole Drilling with Expandable Sand Screens for Low-Cost, High-Deliverability Wells at Bhit Gas Field in Pakistan
Authors: Mehmood A. , Mazzoni R. , Ahmed J. , Arshad M. , Egge G. , Montagna J. 
Published: December 2007

Abstract
The first ever expandable selective sand screen open hole completion in Pakistan was successfully deployed with combined efforts of the Operator and Service Company operations teams. This installation allowed for recovery of a previously suspended well due to drilling complexities, such as top of the mountain air drilling and shallow H2S issues. Additionally, this installation proved the advantages of slim-hole drilling and the economic benefit of large bores to maximize well productivity by lowering the turbulent skin effect in a high rate gas well. The objective was to design a completion for cost effective 6" slim hole drilling without compromising the targeted well production of 90-MMSCFD achievable from conventional 7" monobore completion.
The project targets were met in terms of both productivity and cost with minor contingencies solved on location. Similar expandable installations will lower the capital expenditure of future high rate gas wells for Eni and its JV partners through utilization of slim-hole drilling while achieving large bore for higher productivity targets.
Sand control in open hole unconsolidated sands with inter bedded clay layers may be considered higher risk completions. This paper will discuss and compare alternative technology solutions available for open hole completions. Additionally, this paper will discuss the operational risks of expandable screen systems as well as constraints of other sand control completions options.
Expandable screen for open hole sand control has become a proven technology providing fast installation, wellbore support, zonal isolation, future water control options, reduction in flow turbulence and mechanical skins, resulting in improved productivities.
Practical Application of Probabilistic Approach to Estimate Reserves Using Production-Decline Data
Authors: Cheng Y. , Wang Y. , McVay D. A. , Lee W. J. 
Published: December 2007

Abstract
Analysts have increasingly used probabilistic approaches to evaluate the uncertainty in reserves estimates based on decline curve analysis. This is because the results represent statistical analysis of historical data that usually possess significant amounts of noise. Probabilistic approaches usually provide a distribution of reserves estimates with three confidence levels (P10, P50 and P90) and a corresponding 80% confidence interval. The question arises: how reliable is this 80% confidence interval? In other words, on a large set of analyses, is the true value of reserves contained within this interval 80% of the time? Our investigation indicates that it is common in practice for true values of reserves to lie outside 80% confidence intervals much more than 20% of the time using traditional statistical analyses. This indicates that uncertainty is being underestimated, often significantly. Thus, the challenge in probabilistic reserves estimation using decline curve analysis is not only how to appropriately characterize probabilistic properties of complex production data sets, but also how to determine and then improve the reliability of the uncertainty quantifications.
This paper presents an improved methodology for probabilistic quantification of reserves estimates using decline curve analysis and practical application of the methodology to actual individual well decline curves. Application of our proposed new method to 100 oil and gas wells demonstrates that it provides much wider 80% confidence intervals, which contain the true values approximately 80% of the time. In addition, the method yields more accurate P50 values. Thus, the new methodology provides more reliable probabilistic reserves estimation, which has important impacts on economic risk analysis and reservoir management.
Models and Methods for Determining Transport Properties of Touching-Vug Carbonates
Authors: Zhang L. , Nair N. , Jennings J. W. , Bryant S. L. 
Published: December 2007

Abstract
In some vuggy carbonate rocks, the sizes of the vugs are much larger than that of the matrix pores and different physical models are required for different parts of the pore space. This is particularly true when the vugs are touching, forming a network of directly connected vugs and creating flow pathways unrestricted by matrix resistance. An additional complication is that vug-to-vug connections introduce another important length scale, the scale of the connected clusters, in addition to the scales associated with the vug sizes and the background matrix variability. Flow and transport properties of these vuggy carbonates often deviate from classical theories and meaningful laboratory measurements are difficult when the vugs are larger than plug samples or whole core. Despite the theoretical and experimental difficulties, estimating effective permeabilities and effective dispersivities in these rocks is of great practical importance in modeling petroleum reservoirs and groundwater aquifers.
In this paper we describe an approach to quantify these properties for a particular class of rocks. The approach combines five techniques: 0.5-mm resolution X-ray CT imaging of a 36 cm high – 25 cm diameter sample, capillary-tube models, bench-scale flow experiments, connected-volume computations, and high-resolution numerical simulation of single-phase flow and solute transport. The approach is illustrated with a sample taken from a Cretaceous caprinid reef debris deposit containing vugs as large as 10 cm. The vugs correspond to void space within and between the irregularly packed caprinid shells and fragments. Connectivity analysis of the CT data shows that more than half of the vug volume is in a single touching-vug network. Even so, the connected path of vugs spanning the sample is restricted and many vugs are the large-scale analogues of "dead-end pores". The consequent variation of effective permeability, 35 md - 114 Darcy, is quantified at the scale of 5 to 35 cm computationally and experimentally. Dispersivity in this sample is a non-trivial convolution of at least three phenomena: advection through a flowing-vug network, transfer between the flowing-vug network and dead-end vugs, and transport through the matrix and non-touching vugs.
Integrated Full-Field Review of Betty Field for Building Predictive Models to Reduce Uncertainty in Reserves and Identifying Future Potential
Authors: Kasap E. , Sanza G. , Kario M. W. , Basu T. , Fathy K. , Claverie M. , Waheed A. , Layh B. , Boitel A. , Gajraj A. 
Published: December 2007

Abstract
A multi-discipline integrated full field review (FFR) was conducted for Betty field, offshore Malaysia, in order to build a set of 3D predictive numerical models from multi-scale geological, seismic, petrophysical, reservoir and production engineering data.This study reassessed field stock tank oil initially in-place (STOIIP) volumes and remaining reserves, determined infill drilling potential and identified opportunities to improve both short-term and long-term field performance.Betty field comprises of multiple stacked, laterally continuous, vertically heterogeneous reservoirs. Some reservoirs have experienced relatively high recovery factor (RF) to date (i.e., &gt;69%), while others have underperformed (RF&lt;15%). One of the priorities of this study was to resolve these anomalies.
Detailed evaluation of the core identified five predominant lithofacies in each reservoir. Horizons, which were interpreted from 3D seismic and tied to the well logs, formed the framework for the static model structure. The neural network-based lithofacies analysis for all the wells enabled distribution of the lithofacies data in a 3D geocellular model, which significantly improved the accuracy of the rock property distribution in the reservoirs. Vertical trend functions based on electrofacies logs were input to control the facies content of each layer, and the resultant facies model was used to control the porosity distribution using Sequential Gaussian Simulation (SGS) throughout a fine grid (11 million cells, 1-ft. layers). SGS was also used as co-simulation for permeability, coupled with vertical and horizontal variograms honoring the appropriate facies proportion in each layer.The static model was upscaled (to 600,000 cells, 6-ft layers) after correlating the lithofacies from well to well with over 2800 geological markers to preserve vertical heterogeneity. The initial saturation distribution determined from gravity-capillary equilibrium and a single J-function anchored at the base of the water-oil transition zone, was essentially corroborated by petrophysical analyses.Representative drainage/imbibition relative permeability curves were established from the available data and deployed for dynamic modeling.
As a testament to the integrity of the data, the technical interpretation and overall approach that was used, it was found that almost 75% of the 66 historical completions were essentially matched for 27 years of history after making trial runs of the dynamic model without any adjustments to the static reservoir description.
Measurement of the Sealing Capacity of Shale Caprocks
Authors: Al-Bazali T. M. , Zhang J. , Chenevert M.xs E. , Sharma M. M. 
Published: December 2007

Abstract
Shales play a major role in petroleum exploration and production because they occur both as source rocks and cap-rocks.Their small pore throat size means that very high capillary pressures are required to establish any hydrocarbon saturation in the shales. The minimum capillary entry pressure (trap capacity) defines the maximum height of a hydrocarbon column that can be trapped by a shale.
In this paper, pressure transmission tests were used to experimentally measure capillary entry pressures of various non-wetting fluids (oil-based mud, crude oil. Decane and Nitrogen gas) through different shales.These capillary entry pressures are needed for the estimation of a shale's seal capacity (h).Results show that measured capillary entry pressure (seal capacity) of shales are correlated with other shale properties such as CEC and permeability.The effects of fluid type and interfacial tension on capillary entry pressure of shales were also investigated.Results show that the presence of a hydrocarbon phase (decane) in the shale reduces the shale capillary entry pressure (seal capacity) and significantly increases hydrocarbon flux. Also, the presence of surfactants in the hydrocarbon phase significantly reduces the capillary entry pressure and, therefore, the shale's seal capacity.Measured capillary entry pressures were also used to estimate the pore throat radius of shales.
Since pressure transmission tests are so difficult to run, a quick and easy rig-site electrochemical test on shale cuttings to characterize the capillary entry pressure of drilled shale formations is suggested.
Pressure Effects on Porosity-Log Responses Using Rock Physics Modeling: Implications on Geophysical and Engineering Models as Reservoir Pressure Decreases
Authors: Holmes M. , Holmes A. M. , Holmes D. I. 
Published: December 2007

Abstract
Due to changes in fluid properties, porosity log responses change with pressure, especially for gas/water systems.Velocity data (compressional and shear) can be described using the Krief rock physics model.This model involves relationships among compressional and shear velocities, rock bulk density, elastic moduli of the matrix, shale and fluid components, shear modulus of the solids, and Biot coefficients.Density response is governed by changing gas density as a function of pressure.Neutron response is controlled by hydrogen indicies of the fluids and the excavation effect.
A complete porosity log suite model is presented whereby pseudo porosity logs are calculated as pressure and gas saturation dependent functions.
Matrix and shale properties are included.Additionally mechanical properties with changing pressure and saturation are available.
From compressional travel time and density log responses, changes in synthetic seismograms as reservoir pressure is reduced can be calculated.This application has significant implications in the interpretation of 4-D seismic surveys over reservoirs undergoing pressure depletion.
Estimates of changing mechanical properties as functions of saturation and pressure have a number of engineering applications, including stimulation design and sand control.
Examples from a variety of clastic and carbonate reservoirs are presented, including intermediate depth hard rocks, deep offshore soft rocks, and shallow onshore soft rocks.