bluuebunny/crossref_metadata_2025 huggingface dataset:
Permeability Determination From Well Log Data
Authors: Mohaghegh Shahab , Balan Bogdan , Ameri Samuel
Published: December 2007

We discuss and compare three different approaches for permeability determination from logs from a practical point of view. The three methods, empirical, statistical, and the recently introduced "virtual measurement," make use of empirically determined models, multiple variable regression, and artificial neural networks, respectively. We apply all three methods to well log data from a heterogeneous formation and compare the results with core permeability, which is considered to be the standard. Our comparison focuses on the predictive power of each method.
Simulation of Transients in Natural Gas Pipelines
Authors: Zhou Junyang , Adewumi M. A.
Published: December 2007

Transient flow of natural gas in pipelines is simulated without neglecting the inertia term. The governing equations constitute a non-homogeneous hyperbolic set of first-order quasilinear partial differential equations. The first-order, three-point, explicit Godunov scheme and the second-order, five-point, total variation diminishing (TVD) scheme are used to solve this set of equations. Two examples are simulated. The first is the propagation of a slow transient, with 24-hour cycle, in a 45-mile long, 8-in. inside diameter (ID) transmission pipeline, while the second is propagation of a fast transient in a 24-in., 300-ft long pipe. Comparisons between the predicted results and the measured data are fairly good and appear to be better than the predictions reported in the literature. This suggests that the mathematical model presented in the present study, which includes the inertia term in the momentum equation, is more realistic and the numerical schemes used are more robust.
Kinetics of Tertiary Reactions of Hydrofluoric Acid on Aluminosilicates
Authors: Gdanski Rick
Published: December 2007

The standard description of hydrofluoric acid (HF) acidizing chemistry clearly demonstrates a primary and secondary reaction of HF with aluminosilicates.1 Field experience has taught our industry that possible precipitation during the secondary reaction can adversely affect treatment success.2 This statement has been particularly true in formations with high K-feldspar content or formations having temperatures above 300°F. Recent work has also reported the existence of a third, or tertiary, reaction of HF with aluminosilicates.3

This paper reports how the rate law and kinetics for this tertiary reaction are determined on kaolinite and feldspar over a broad temperature range. This document also discusses the discovery of how most clays were thermally unstable to HCl at temperatures above 250°F. These findings were made possible by recently applied experimental techniques including 19F nuclear magnetic resonance (NMR) spectroscopy,3 fractional pore-volume (PV) flow experiments,4 and an accurate knowledge of the HF stoichiometry.5

The tertiary reaction of aluminum fluorides, AlFx (where x is the average F/Al ratio), with clay was slow below 200°F and was dominated by HCl decomposition of the clay above 250°F. The tertiary reaction required the presence and consumption of acid to proceed. Feldspars were very stable in HCl at all temperatures, whereas every clay tested had a temperature above which it was easily decomposed by HCl. Ion-exchanging clays tended to be the least stable of the clays, whereas kaolinite was the most stable clay.
Clay Swelling Diagrams: Their Applications in Formation Damage Control
Authors: Zhou Zhihong (John) , Cameron Shauna , Kadatz Bernice , Gunter William D.
Published: December 2007

A novel method has been developed to quantify clay swelling in aqueous solutions. In this method, a swelling clay is dispersed into an aqueous solution of desired composition, and then mounted in a special cell for X-ray diffraction (XRD) analysis. Using this method, the effects of solution pH, salinity, cation composition, temperature, fluid pressure, and overburden pressure on clay swelling can all be determined efficiently. This method uses only a small amount of sample and offers some advantages over the conventional coreflood method. It can also be used to evaluate the performance of clay stabilizers. We have determined the critical salt concentration (CSC) and critical cation ratio (e.g., Na/Ca, Na/K) for macroscopic osmotic swelling of the most common swelling clays. The information can be represented by a set of swelling diagrams in which the solution composition responsible for osmotic swelling and formation damage is delineated. The swelling diagrams can be used to determine the compatibility between shales and drilling fluids, between swelling clays and drilling filtrate or completion fluids, and between swelling clays and flooding fluids used in EOR. The effects of temperature and pressure on clay swelling have also been quantified using this method. Temperature has a small effect on clay swelling between 20-100°C; but the differential pressure between the overburden and fluid pressures (Po - Pf) has a significant effect on clay swelling. The greater the differential pressure, the less the clay swells. The important implications of these results on petroleum drilling and production will be discussed. It should be cautioned that the swelling diagrams can not be applied to fines migration problems associated with non-swelling clays such as kaolinite and illite.
Integrating Engineering and Operations for Successful HTHP Exploratory Drilling.
Authors: Smith J. R. , Cade R. S. , Gatte R. D.
Published: December 2007

The Amoco Matagorda Island 636 No. 1 exploratory well was successfully drilled to 18,834 ft in 85 days. Both the depth and the drilling time were industry records for the 50-block area on trend with the well. The 357°F bottomhole temperature, required mud weights of up to 18.5 lbm/gal, more than 8,000 ft of overpressured section, more than 2,000 ft of previously unexplored section, and the historical drilling problems in the area combined to make this well a special challenge. The results validate the strategy that was developed to integrate engineering and operations as an example of how to meet such challenges successfully.

This paper focuses on describing this strategy, how it was developed and applied, and the results achieved relative to previous industry performance in the area. Planning, innovation, and teamwork were the crucial components of the strategy and are discussed in detail. Specific examples of techniques, technology, tools, and our tactics for applying them are provided. These ranged from rigorous application of important industry standard practices to pure experimentation (with previously untried bit designs) and included a comprehensive effort to achieve a positive synergy within both the drilling system we assembled and our organization for its operation.
Optimal Transformations for Multiple Regression: Application to Permeability Estimation From Well Logs
Authors: Xue Guoping , Datta-Gupta Akhil , Valkó Peter , Blasingame Tom
Published: December 2007

Conventional multiple regression for permeability estimation from well logs requires a functional relationship to be presumed. Because of the inexact nature of the relationship between petrophysical variables, it is not always possible to identify the underlying functional form between dependent and independent variables in advance. When large variations in petrological properties are exhibited, parametric regression often fails or leads to unstable and erroneous results, especially for multivariate cases.

In this paper, we describe a nonparametric approach for estimating optimal transformations of petrophysical data to obtain the maximum correlation between observed variables. The approach does not require a priori assumptions of a functional form, and the optimal transformations are derived solely based on the data set. Unlike neural networks, such transformations can facilitate physically based function identification. An iterative procedure involving the alternating conditional expectation (ACE) forms the basis of our approach. The power of ACE is illustrated using synthetic as well as field examples. The results clearly demonstrate improved permeability estimation by ACE compared to conventional parametric-regression methods.
Effect of Pressure on Improved Oilflood Recovery From Tertiary Gas Injection
Authors: Grigg R. B. , Gregory M. D. , Purkaple J. D.
Published: December 2007

Twenty-eight tertiary gas-injection corefloods were conducted to define the pressure/recovery curves for five crude oils. These results have been compared with slim-tube recovery tests using the same five reservoir fluids. Field-scale CO2 floods have been or are currently under way in three of the studied reservoirs (S, H, and M). The other two reservoirs (F and A) have been considered for CO2 and hydrocarbon-gas injection, respectively. The results for the four CO2 injection systems consistently showed that oil recovery decreases dramatically below the minimum miscibility pressure (MMP) exactly like slim-tube tests, while the recovery in the hydrocarbon-gas injection system decreased almost linearly with decreasing pressure both above and below the MMP. To use short cores, it is expedient to use an external transition-zone generator. A method has been developed that successfully circumvents the oil resaturation problem caused by most transition-zone generators.
Influence of Syneresis on Permeability Reduction by Polymer Gels
Authors: Bryant S. L. , Rabaioli M. R. , Lockhart T. P.
Published: December 2007

Syneresis is commonly believed to be incompatible with the application of polymer gels to reduce the permeability of porous media. In this paper, it is shown that, although the permeability of a geltreated porous medium does increase as syneresis proceeds, the degree of permeability reduction in cores remains technologically useful even when 95% syneresis is observed in bulk samples. Arguments are presented for the preferential shrinking of syneresed gel into pore throats; this model explains why permeability reduction is maintained and accounts for several other experimental results. The absence of performance penalties for syneresis has significant implications for the applicability of gels for water shutoff treatments in matrix formations. For example, it raises the possibility that polymer gels can be applied successfully in situations previously considered unfeasible because of the difficulty of maintaining gel stability, e.g., at high temperatures or in the presence of hard formation brines.
Water Control in Producing Wells: Influence of an Adsorbed-Polymer Layer on Relative Permeabilities and Capillary Pressure
Authors: Barreau Patrick , Bertin Henri , Lasseux Didier , Giénat Philippe , Zaitoun Alan
Published: December 2007

To determine modifications of oil/water two-phase-flow properties after injection of water-soluble polymers, unsteady-state flow experiments were performed on both water- and oil-wet (silanetreated) sandstones. The same imbibition cycle (water displacing oil) under the same conditions was performed on the same core, first without any polymer and then after polyacrylamide had been adsorbed within the core. The capillary pressure was measured directly along the core by use of water- and oil-wet semipermeable membranes, while relative permeabilities were determined from the measurement of the saturation profile (by gamma ray absorption), outlet fluid production, and pressure drop.

The action of adsorbed polymer on relative permeabilities was found to be the same with both water- and oil-wet cores (i.e. a selective reduction of the relative permeability to water with respect to the relative permeability to oil). The trend was somewhat different for the capillary pressure. For the case of water-wet sandstones, the capillary pressure remained positive but increased dramatically after polymer adsorption. Because the polymer has little effect on the interfacial tension (IFT), this effect was attributed to the reduction of pore-throat size caused by macromolecule adsorption and to a possible improvement of the wettability of the core to water. For the case of oil-wet sandstone, the capillary pressure curve moved from negative to positive values, indicating that, in addition to pore-size restriction, the wettability of the core changed after polymer adsorption. This wettability change also induced a dramatic drop in residual oil saturation (ROS).
3-D Pore-Scale Modelling of Sandstones and Flow Simulations in the Pore Networks
Authors: Bakke Stig , Øren Pål-Eric
Published: December 2007

A new method for generating realistic homogenous and heterogeneous 3-D pore-scale sandstone models is presented. The essence of our method is to build sandstone models which are analogs of actual sandstones by numerically modelling the results of the main sandstone-forming geological processes - sandgrain sedimentation, compaction, and diagenesis. The input data for the modelling are obtained from image analyses of thin section images of the actual sandstone.

The spatial continuity of the sandstone model in the X, Y, and Z directions is determined using a scale-independent invasion percolation based algorithm. The resulting spatial continuity function, which is an ellipsoid, may be used as a heterogeneity descriptor for the sandstone model. Heterogeneity analyses show that compaction reduces the spatial continuity in the horizontal direction more rapidly than in the vertical one.

The architecture and geometry of the network representation of the pore space are determined by applying various 3-D image analysis algorithms directly on the fully characterised sandstone model. A 3-D pore network which was generated from thin section data from a strongly water wet Bentheimer sandstone is used as input to a two-phase network flow simulator. Simulated transport properties for the sandstone model are in good agreement with those determined experimentally.
Ekofisk Field Reservoir Characterization: Mapping Permeability Through Facies and Fracture Intensity
Authors: Agarwal Bijan , Allen L. R. , Farrell H. E.
Published: December 2007

The development of a strategy for the detailed three-dimensional (3D) description of permeability was a key ingredient of the recent reservoir characterization study of the Ekofisk field. Because the ultimate objective of this characterization effort was the construction of a new full-field 3D reservoir flow model, permeability and its heterogeneity received special focus. Permeability has a tremendous influence on history matching of reservoir fluid flow models and, in turn, reservoir-management decisions. This is particularly true in a mature, waterflooded field such as Ekofisk.

The Ekofisk field is a high-porosity, low-matrix permeability naturally fractured chalk. Fluid-flow characteristics of the reservoir are largely governed by the distribution, orientation, and interconnectivity of the natural-fracture system. To honor this mechanism, an algorithm was developed based on the log linear relationship between fracture spacing (intensity) data from core and well-test effective permeability. To capture the intrinsic heterogeneity and complex nature of Ekofisk field, the basic relationship between fracture intensity and permeability was modified to incorporate variations associated with (1) chalk facies (2) fracture type; (3) porosity; (4) structural location; (5) structural curvature; and (6) silica content.

To calibrate the algorithm, permeability determined from distributing total well-test flow capacity (kh) based on production log contribution was used as a tuning parameter. As a final step, geostatistical techniques were used to ensure that permeabilities derived from the algorithm matched those obtained from well-test analysis.
Productivity of Fractured Gas-Condensate Wells: A Case Study of the Smorbukk Field
Authors: Settari Antonin , Bachman R. C. , Hovem K. A. , Paulsen S. G.
Published: December 2007

This paper describes a systematic study of the effect of condensate blockage on the productivity index (PI) of hydraulically fractured wells in a complex, highly heterogeneous reservoir containing rich gas condensate. The study was performed for the Smorbukk field offshore Norway with sophisticated simulation models. The techniques used are general, and the study findings apply as guidelines in general to fractured gas-condensate wells. Proppant fracturing is capable of restoring most of the productivity lost owing to liquid buildup. The effectiveness depends primarily on the reservoir heterogeneity, fracture length and conductivity. The relative benefits of fracturing decrease in highly heterogeneous formations.
Options for Small-Scale Sulfur Recovery
Authors: Royan Tom , Wichert Edward
Published: December 2007

With the issuance by the Alberta Energy Resources Conservation Board and Alberta Environment of their report entitled Sulphur Recovery Guidelines for Sour Gas Plants in Alberta in August of 1988, the requirement in Alberta to recover sulfur was broadened to a sulfur content of 1 tonne/D or greater in the inlet gas to a new sour-gas treating plant. This paper reviews the processes in use for recovering sulfur from sour-natural-gas streams that have a total sulfur content of 5 tonne/D or less. These processes are the modified Claus process, the recycle Selectox process, and the reduction/oxidation processes LO-CAT and SulFerox. While the modified Claus process is used in large sulfur-recovery plants, the other processes may be more economical for sulfur recovery on a small scale. A description of the sour-gas treating and sulfur-recovery processes is given, and a comparison of estimated capital and operating costs for typical sour-gas streams is provided.

All of the above processes are in operation in North America. Operating experiences with these processes in Alberta are discussed. The quality of the end-product sulfur varies among these processes, and the options for sulfur disposal are reviewed.
A Relative Permeability Modifier for Water Control of Gas Wells in a Low-Permeability Reservoir
Authors: Tielong Chen , Yong Zhao , Kezong Peng , Wanfeng Pu
Published: December 2007

Water control in gas wells is a major measure to enhance gas recovery. The work is concentrated on finding a highly selective polymer to reduce water production without affecting gas production from gas wells in low-permeability reservoirs. This paper presents the conceptions of residual resistance factors (RRF's) to both wetting and non-wetting phases and the laboratory experimental and field trial results of relative permeability modifiers for water control in gas wells.
On the Determination of Reservoir Pressure When Radial-Flow Conditions Are Nonexistent
Authors: Raghavan Rajagopal , Chu Wei Chun
Published: December 2007

We present a new method to determine average pressure. This method is particularly suited for situations in which no record of the pseudoradial-flow period exists, which is the case in many low-permeability reservoirs. The assumptions of the method we propose are identical to conventional methods, except that the pseudoradial-flow period need not exist. The method may be used in channel-type reservoirs. Example illustrations are presented.
Asphalt Formation and Precipitation: Experimental Studies and Theoretical Modelling
Authors: Sahimi Muhammad , Rassamdana Hossein , Dabir Bahram
Published: December 2007

Extensive new experimental data are presented for the amount of precipitated asphalt and asphaltene aggregates formed with crude oil and various precipitating agents, and their molecular weight (MW) distributions. A new scaling equation is proposed for predicting the onset and amount of the precipitates, which is similar to those encountered in aggregation phenomena. The scaling function takes on a very simple form, and its predictions are in very good agreement with the data. Small-angle X-ray and neutron scattering data are analyzed to delineate the structure of the asphalt and asphaltene aggregates. The analysis suggests that asphalt and asphaltene aggregates are fractal structures with well-defined fractal properties. The mechanisms that give rise to such fractal aggregates are identified, based on which a new analytical equation for the MW distribution of asphalt and asphaltene aggregates is proposed which provides accurate predictions for the data.
Modeling Asphaltene Precipitation During Primary Depletion
Authors: Nghiem Long X. , Coombe Dennis A.
Published: December 2007

This paper describes a thennodynamic model for asphaltene that captures the behavior of asphaltene precipitation during primary depletion. Precipitation occurs above the saturation pressure, reaches a maximum value around the saturation pressure, and decreases as the pressure drops further. The precipitated asphaltene is represented as a pure solid, with the oil and gas phases modeled with an equation of state (EOS). A validation of the model",:ith exp~rimental data is reported. A study of the sensitivity of the model to different parameters IS described.
General Three-Phase Relative Permeability Model for Prudhoe Bay
Authors: Jerauld G. R.
Published: December 2007

This paper describes two- and three-phase relative permeability concepts important for Prudhoe Bay. It includes a three-phase relative permeability correlation that incorporates hysteresis in gas, oil, and water relative permeability as well as the dependence of relative permeability on composition and gas/oil interfacial tension (IFT). The functional forms chosen to correlate the relative permeability data were based on interpretation of the pore-level mechanisms that determine fluid flow. The three-phase correlation reduces to traditional models in various limits and is more consistent with available data and trends in the literature than previous correlations. Although this correlation was developed for Prudhoe Bay, it can be and has been applied to other mixed-wet reservoirs with changes in the input parameters. The correlation is particularly useful in situations where both compositional effects and hysteresis are important.
Hydrocarbon Production Scheduling With Genetic Algorithms
Authors: Harding T. J. , Radcliffe N. J. , King P. R.
Published: December 2007

This paper describes the application of stochastic search techniques to the production scheduling of a group of linked oil and gas fields. The goal was to maximize the total net present value (NPV). A genetic algorithm with problem-specific crossover operators was particularly successful in this respect.
Towards Risk-Based Well Separation Rules
Authors: Williamson H. S.
Published: December 2007

In previous descriptions of the application of quantitative risk assessment (QRA) to subsurface well collisions, several key parts of the analysis have been missing. In particular, no allowance has been made for human error, the distribution of survey errors has not been adequately investigated, and no distinction has been made between real and modeled risks. This precludes immediate application of the technique in cases where personnel or the environment are at risk.

These three problem areas each require a challenging analysis, but their resolution would provide a generally applicable risk-based well separation rule. Moreover, once such a rule were in place, there would be several options for further reducing well separations without relaxing the tolerable risk levels.

When neither personnel nor the environment are at risk, the problems with the basic analysis are less acute. The technique is currently being applied operationally in these cases.
Induction Log Shoulder-Bed Corrections to Anisotropic Formations and the Effect of Shale Anisotropy in Thinly Laminated Sand/Shale Sequences
Authors: Hagiwara Teruhiko
Published: December 2007

We examine induction log responses to layered, dipping, and anisotropic formations analytically. The analytical model is especially helpful in understanding induction log responses to thinly laminated binary formations, such as sand/shale sequences that exhibit macro-scopically anisotropic resistivity. We discuss two applications of the analytical model.

In one application, we examine special induction log shoulder-bed corrections for use when thin anisotropic beds are encountered. It is known that thinly laminated sand/shale sequences act as macroscopically anisotropic formations. Hydrocarbon-bearing formations also act as macroscopically anisotropic formations when they consist of alternating layers of different grainsize distributions. When such formations are thick, induction logs accurately read the macroscopic conductivity, from which the hydrocarbon saturation in the formations can be computed. When the laminated formations are not thick, proper shoulderbed corrections (or thinbed corrections) should be applied to obtain the true macroscopic formation conductivity and to estimate the hydrocarbon saturation more accurately.

We use the analytical model to calculate the thinbed effect and to evaluate the shoulder-bed corrections. We show that the formation resistivity and, hence, the hydrocarbon saturation are greatly overestimated when the anisotropy effect is not accounted for and conventional shoulder-bed corrections are applied to the log responses from such laminated formations.

In another application, we examine the effect of shale anisotropy in thinly laminated sand/shale sequences. How do induction logs respond to such laminated formations when shale laminae are anisotropic? How accurate are the estimates of the sand-laminae resistivity and of the hydrocarbon saturation in these sand laminae? To answer these questions, we used the analytical model to examine the effect of shale lamina anisotropy on induction log responses in thinly laminated formations. We learned that the macroscopic conductivity of a laminated formation is determined uniquely by the sandlaminae conductivity and the anisotropic shale conductivity, if the sand fraction is known. We also found that the sand resistivity estimate depends on the value of shale resistivity and the dip angle, if the shale is assumed to be isotropic and if the sand fraction is known. When the sand fraction is not known, the sand resistivity and the sand fraction can be estimated if the set of horizontal and vertical macroscopic resistivities is known. In this case, the sand resistivity tends to be overestimated if the shale anisotropy is not accounted for. On the other hand, the sand fraction estimate is generally insensitive to the shale anisotropy, except for low sand-laminae resistivity (Rsd/Rsh < 5).
Application of Sequence Stratigraphic Reinterpretation of Lower Lagunillas Member to Further Development of Bloque IV, Lake Maracaibo, Venezuela
Authors: Bryant I. D. , Herron M. M. , Villarroel H. Gamero de
Published: December 2007

Discovered in 1955, the Lower Lagunillas member reservoir of the Miocene Lagunillas formation of Bloques III and IV of the Bachaquero field was originally estimated to contain 2 billion barrels of oil. This reservoir interval traditionally has been interpreted to have been deposited in a delta plain setting and to comprise three reservoir subdivisions that were developed as a single drainage unit. Field performance, however, has indicated that the reservoir is more complex; the present study was initiated to provide a revised development strategy.

Sedimentological interpretation of four cored wells has led to the development of a new model of deposition in tidally influenced lower delta plain and delta-front settings. This model is supported by Fourier transform infrared (FT-IR) measurement of clay concentrations and prompt neutron capture boron measurements that are indicative of a brackish water-depositional setting. We used this geological model to guide correlation of wireline logs from 46 wells in the central part of Bloque IV and to provide a high-resolution sequence stratigraphic model of the Lower Lagunillas reservoir. Eleven genetic layers are identified that are separated by locally developed intraformational seals into up to eight drainage units. High permeability, tidally influenced channel-fill sands have acted as preferential conduits for gas influx, leaving bypassed oil in lower quality sands that were deposited as tidal deltas and bars. This reservoir model has been supported by re-examination of production data and by openhole measurements in a recent infill well and cased- hole logging of two other wells in the study area. The new model will form the basis for redevelopment of the Lower Lagunillas reservoir to increase recovery further from this mature field.
New Tools Target Oil-Quality Sweetspots in Viscous-Oil Accumulations
Authors: Smalley P. C. , Goodwin N. S. , Dillon J. F. , Bidinger C. R. , Drozd R. J.
Published: December 2007

Shallow oil fields frequently contain oils that not only have low oil gravity and high viscosities, but are also highly variable in terms of these properties. It is thus crucial to gather sufficient oil-quality data to sample a statistical cross section of the oil population. This paper describes how oil gravity and dead-oil viscosity can be predicted from geochemical parameters that can be measured on core or sidewall core samples, thus allowing oil samples to be accessed with greater spatial coverage than could reasonably be achieved with conventional fluid sampling. This technique is demonstrated on cored wells from the large Schrader Bluff viscous oil accumulation in Milne Point, Alaska. An oil can inherit a particular oil gravity or viscosity for a variety of causes. Consequently, spatial variations in such bulk-oil properties can be difficult to map empirically simply by contouring data because more than one controlling factor may be operative. A major step forward in fluid mapping is to identify and quantify these controls and map the controls. In Schrader Bluff the controls were discovered to be the degree of biodegradation and the presence of an in-mixed second charge of (light) oil. Variations in these processes can be tracked with geochemical parameters and mapped with a much greater degree of certainty than the bulk-oil properties. The resulting individual maps may then be combined to predict oil gravity and viscosity. Conceptual models exist for these processes, opening the possibility of model-driven prediction of oil properties and sweetspots in areas away from well control.
Salinity, Temperature, Oil Composition, and Oil Recovery by Waterflooding
Authors: Tang G. Q. , Morrow N. R.
Published: December 2007

The effect of aging and displacement temperatures and brine and oil composition on wettability and the recovery of crude oil by spontaneous imbibition and waterflooding has been investigated. This study is based on displacement tests in Berea sandstone with three crude oils and three reservoir brines (RB's). Salinity was varied by changing the concentration of total dissolved solids (TDS's) of the synthetic brine in proportion. Salinity of the connate and invading brines can have a major influence on wettability and oil recovery at reservoir temperature. Oil recovery increased over that for the RB with dilution of both the initial (connate) and invading brine or dilution of either. Aging and displacement temperatures were varied independently. For all crude oils, water wetness and oil recovery increased with increase in displacement temperature. Removal of light components from the crude oil resulted in increased water wetness. Addition of alkanes to the crude oil reduced the water wetness, and increased oil recovery. Relationships between waterflood recovery and rate and extent of oil recovery by spontaneous imbibition are summarized.
Material-Balance Calculations in Tight-Gas Reservoirs: The Pitfalls of p/z Plots and a More Accurate Technique
Authors: Payne David A.
Published: December 2007

Through the use of theoretical and field examples, the potentially large errors associated with use of straight-line p/z decline (tank) analysis to assess gas in place (GIP) and reserves in tight-gas reservoirs are illustrated. The basic tank assumption that reservoir pressure gradients are small can be violated, even with long shut-in times. It is also demonstrated that a reasonably-straight-line p/z decline does not necessarily indicate that the reservoir behaves as a tank. The communicating reservoir (CR) model is presented as a simple, yet much more accurate, method of performing materialbalance calculations in tight reservoirs. The results of the application of the CR model to the Waterton gas field are used to illustrate the success and large impact that can be obtained by examining the pressure behavior more closely than simply plotting p/z.
Effect of Wafer Saturation on Oil Recovery by Near-Miscible Gas Injection
Authors: Wylie Philip , Mohanty Kishore K.
Published: December 2007

During gas injection, bypassing of oil is common because of gravitational, viscous, and/or heterogeneity effects. The oil in the bypassed regions can be recovered through enhanced flow and mass transfer between the bypassed region and the injectant gas. Previously, experiments in our laboratory have been carried out to evaluate the effects of phase behavior and capillary crossflow in near-miscible gasfloods; however, these studies were conducted in the absence of water. In this paper, we evaluate the effects of water saturation on oil bypassing and the rate of mass transfer from the bypassed zones. Injectant gases are first-contact miscible (FCM), multicontact miscible (MCM), or submiscible with the bypassed oil. Gasfloods are conducted in different orientations with different levels of water saturation. Mass-transfer experiments are carried out to isolate and investigate mass-transfer mechanisms. Results indicate that oil recovery from vertical, submiscible gasfloods is not influenced by water-saturation level. Horizontal gasfloods showed evidence of less gravity override in the presence of water. The mass-transfer experiments showed that recovery increases with enrichment and is reduced by the presence of water. Effective diffusion coefficients are estimated as functions of water saturation and enrichment.
The Successive Displacement Process: Oil Recovery During Blowdown
Authors: Irwin D. D. , Batycky J. P.
Published: December 2007

Much of western Canada's conventional crude oil occurs in vertically continuous reefal carbonate structures. A common strategy has been to support oil production through downward vertical gas displacement. The gravity-stable displacement yields excellent conformance and high oil recoveries, with typical residual levels of 20% pore volume (PV). Once the oil zone has been depleted, leaving only a sandwich loss, the pools enter a blowdown phase to produce the gas cap from the top of structure. During the blowdown phase, if there is an underlying aquifer, the oil sandwich is displaced upward into the previously gas-displaced oil zone, trapping gas. Owing to the presence of the trapped-gas saturation, the remaining oil saturation in this zone, is reduced to near miscible levels (10 to 15% PV) as it is displaced by the underlying water, mobilizing incremental oil equal to 5 to 10% PV. When an aquifer is not present, bottomwater injection can be applied to ensure displacement through the entire gas-displaced oil zone. The successive displacement process (SDP), as this tertiary waterflood concept has been named, has been confirmed with full-diameter reservoir-condition core tests on carbonate cores in the laboratory. Observation from the initial stages of a full-field SDP application in Imperial Oil's Bonnie Glen reservoir after approximately 4 years of operation provides further encouragement, with performance indicating a reduction in the oil residual of 5 to 6% PV.
Monitoring and Analysis of ECP-lnflation Status Using Memory-Gauge Data
Authors: Gai Huawen , Elliot Graname
Published: December 2007

The current surface instrumentation for monitoring the external-casing-packer (ECP) -inflation status has been identified as unsatisfactory, causing a significant degree of uncertainty in the evaluation of ECP performance. Coupled with some unreliable practices in the installation process relating to the use of the instrumentation, data interpretation is often difficult.

To combat the inaccuracy of surface measurement, memory gauges have been used for the first time as a retrospective tool to monitor ECP status downhole in west Shetland. The memory gauges, which are mounted on the workstring close to the ECP, remove the damping effect of the fluid column in the workstring, and are capable of measuring the squeeze pressure below the ECP caused by inflation. It is demonstrated in these operations that the following have been achieved.

• ECP status has been identified unambiguously and reliably in several wells.

• Some problems in job design have been identified, such as hydraulic lock (which may result in partial inflation) and incorrect setting of pressure shear-pin levels for inflation, leading to the formation being fractured.

• Insight has been gained in pipe-movement-induced swabbing and pressure surge, which act adversely on the formation. Certain information on the mud (such as solid settlement and pressure/volume relations) was also obtained.

• Valuable data was gained (both from the memory gauges and the surface gauges) that were a cornerstone for setting certain guidelines in interpreting ECP status by surface instrumentation.

This paper presents a detailed analysis of the data with examples and case histories. Key considerations in operations, lessons learned, and recommendations are discussed before the conclusions are reported.
Experimental and Modeling Studies of Two-Phase Flow in Pipelines
Authors: Manabe Ryo , Tochikawa Tetsuro , Tsukuda M. , Arihara Norio
Published: December 2007

The objectives of this study are to develop and evaluate a mechanistic model for gas/liquid two-phase flow in pipelines.

A mechanistic model has been developed by combining currently available models and correlations. The approach of the modeling study was based on the work by Xiao et al.1 Modifications have been made on the annular flow model by implementing the currently developed film-thickness-distribution model.

An experimental database has been developed for model evaluation. Seventy-five runs of steady-state air/water flow tests in horizontal and slightly inclined pipes were conducted using a large-scale experimental facility. The experimental program was set up in a wide range of experimental conditions to cover the intermittent, dispersed bubble, and annular flow patterns.

An evaluation of the model was carried out for each flow pattern, namely, intermittent, dispersed bubble, and annular flow. The comparisons between the measured and calculated pressure drops show good agreement for each flow pattern. Also, overall evaluation revealed that the proposed model provided the best performance among the commonly used empirical correlations, such as Beggs and Brill,2 Mukherjee and Brill,3 and Dukler et al.4
Wettability Changes Induced by Adsorption of Asphaltenes
Authors: Yan Jienian , Plancher Henry , Morrow N. R.
Published: December 2007

Asphaltene fractions were precipitated from two crude oils (designated as Prudhoe Bay '95 and Wyoming '95) by addition of n-hexane. A solution of 250 mg/L of asphaltenes in toluene was used to induce wettability changes in Berea sandstone cores by flow of asphaltene solutions through the core. Concentration of asphaltenes in the effluent was measured by ultraviolet (UV) absorbance. Wettability changes were assessed from measurements of the rate of spontaneous imbibition for changes in initial water saturation and brine composition. Water wetness decreased markedly with increase in ionic strength, increase in cation valency, and decrease in initial water saturation. For comparable conditions, changing the brine anions (chloride, nitrate, carbonate, and sulphate) caused lesser but fairly consistent changes in wetting. Wetting changes induced by asphaltenes from the Wyoming '95 crude oil were always higher than for those prepared from the Prudhoe Bay '95 crude oil. Water-flood recoveries for NaCl, CaCl2, and AlCl3 brines (0.09 M) increased with decrease in water wetness, with recovery reaching a maximum at an Amott wettability index of about 0.2. This result agrees with results reported previously for wettability changes induced by adsorption from crude oil.
Parallel Finite Element Simulation of Miscible Displacements in Porous Media
Authors: Coutinho Alvaro L. G. A. , Alves José L. D.
Published: December 2007

In this work, parallel finite element techniques for the simulation of miscible displacements in porous media are addressed. The pressure equation is approximated by Galerkin's method and the velocity field computed through a post-processing approach to recover the required accuracy. The concentration equation is approximated in space by the Streamline Upwind Petrov Galerkin (SUPG) plus a discontinuity-capturing operator. The resulting semi-discrete equations are approximated in time by a predictor-multicorrector algorithm. To increase the robustness of our solution scheme, the feedback control theory is used to select the proper time-step. The pressure, velocity and concentration linear systems of equations are solved with parallel element-by-element iterative techniques. Performance measurements on two different machines, the CRAY Y-MP and the CRAY C90, for a five-spot pattern with high mobility ratio on random heterogeneous media are presented to show that the numerical techniques employed are accurate and result in a fast code.
Viscosity Reduction Of Hydraulic Fracturing Fluids Through Enzymatic Hydrolysis
Authors: Tayal Akash , Kelly Robert M. , Khan Saad A.
Published: December 2007

High viscosity formulations of guar are used as fracturing fluids to enhance oil and gas production. Following fracturing, these fluids are hydrolyzed and flushed out of the well to provide outflow for oil or gas. Enzymes offer an effective and environmentally benign method for hydrolyzing the guar to a low viscosity fluid. In this study, we used steady shear rheometry to elicit fundamental information on the capabilities and limitations of enzymes. The effect of commercial and new thermostable enzymes on polymer viscosity was investigated in terms of process variables such as temperature of hydrolysis, pH of solution and enzyme concentration. The commercial enzyme was most effective in degrading the guar at slightly acidic conditions and up to 60°C. Above 60°C, the extent of hydrolysis of guar solutions decreased. With increasing temperature, enzymatic activity increased but enzyme stability decreased and this balance was critical in determining the extent of viscosity reduction. Experiments using preheated enzyme also revealed lower viscosity reduction, suggesting that most of the hydrolysis occurs during the enzyme heat up, following which the enzymes deactivate rapidly. Similar experiments with the thermostable enzyme system demonstrated high levels of viscosity reduction at elevated temperatures (up to 85°C) and limited viscosity reduction at ambient conditions. This is suggestive of enhanced capability of this enzyme system at elevated temperatures compared to that of the commercial system. Experiments using purified enzymes from both enzyme systems also revealed that the largest reduction in viscosity of guar solutions occurs with endo-β-D mannanase, the enzyme cleaving the bonds between the mannose backbone units.
Simulation of Transient Well-Test Signatures for Geologically Realistic Faults in Sandstone Reservoirs
Authors: Matthäi Stephan K. , Aydin Atilla , Pollard David D. , Roberts Stephen G.
Published: December 2007

For the design of production strategies one must identify how faults that are detected in seismic surveys influence fluid flow in hydrocarbon reservoirs. In this study we use the Entrada sandstone formation, Arches Natl. Park, Utah, as an outcrop analog of a faulted sandstone reservoir. Field measurements of the geometry, thickness, and layered permeability of the normal faults that crosscut this sandstone are incorporated in two-dimensional (2D) fluid- flow models, facilitating the simulation of fault signatures in transient well tests with a high-resolution finite-element method.

In our simulations, structure and inhomogeneous permeability lead to fault signatures in derivative plots that differ significantly from those of idealized impermeable barriers. Highly permeable slip planes facing the well create the illusion of a nonsealing or nonexisting fault because remote fluids are focused along the slip planes toward the well. Measured low, fault-normal permeability shields fault-bounded blocks of the analog sandstone reservoir from drawdown and large pressure differentials build up across faults during production.

Thus, test data from a single well are insufficient to assess the flow properties of a nearby fault with an inhomogeneous permeability like the normal faults in the Arches Natl. Park. Test responses from multiple wells need to be considered to detect fault segmentation or fault terminations even if the general fault trend is underpinned by seismic data. Flow paths in the reservoir during production are complex. Importantly, formation water is likely to flow into the reservoir along the permeable slip planes of the normal faults.
Identification of Reservoir Heterogeneities Using Tracer Breakthrough Profiles and Genetic Algorithms
Authors: Guerreiro J. N. C. , Barbosa H. J. C. , Garcia E. L. M. , Loula A. F. D. , Malta S. M. C.
Published: December 2007

In this paper, we describe a methodology to identify reservoir properties by using numerical techniques that combine finite element methods, a streamline approach, and genetic algorithms. As a model problem, we consider the system of equations governing incompressible miscible displacement in two dimensions (2D) in which the solution furnishes tracer breakthrough profiles that are parametrized as functions of the properties to be determined. Given a population of initial parameters, after the solution of the model problem and the comparison of each profile with a target one, we evolve to a new population, following the concepts of genetic algorithms and according to the fitness of each member of the previous population.
Mathematical Modeling of Secondary Precipitation From Sandstone Acidizing
Authors: Li Y.-H. , Fambrough J. D. , Montgomery C. T.
Published: December 2007

Field and laboratory experience clearly demonstrates that, besides primary dissolution, precipitation from both secondary and tertiary reactions with aluminosilicates adversely affects matrix acid treatment success. In the secondary reaction, fluosilicic acid from the primary dissolution will further react with aluminosilicates to form hydrated silica on the matrix surface. In the tertiary reaction, aluminum fluoride also extracts aluminum from aluminosilicates to form silica gel by lowering the fluoride/aluminum (F/Al) ratio in the solution. In the presence of a high concentration of metal ions, metal fluorides and fluosilicates are also likely to precipitate.

An optimum acidizing design package can be derived for a specific formation mineralogy and damage mechanism if this complex reactive system can be modeled properly. A geochemical model for acidizing has been developed for this purpose. The numerical simulator is a reactive flow model that solves the reactive system with both reaction kinetics and chemical equilibrium calculations. All possible reactions among all species in the system are solved simultaneously. As acid spends, the computer simulation shows the progress of aluminosilicate dissolution and the formation of different precipitates as the change of dissolved species along the reaction path occurs. The evolution of the damage skin can be evaluated as simulation continues. On the basis of simulation, different pumping schedules with different types of acids can be quickly evaluated to optimize treatment volume and minimize precipitation of hydrated silica and other precipitates.

To validate the model, a series of laboratory coreflood tests has been fully analyzed. The results indicate that the formation of silica gel is significant, on the basis of hydrofluoric acid (HF) effluent analysis. The same set of kinetic data derived from the laboratory coreflood data adequately predicts and explains a sandstone acidizing field case.