bluuebunny/crossref_metadata_2025 huggingface dataset:
Effects of Organic Acids and Bases, and Oil Composition on Wettability
Authors: Skauge A. , Standal S. , Boe S. O. , Skauge T. , Blokhus A. M.
Published: December 2007

Correlations between acid and base numbers, crude oil composition and wettability for crude oil/water/quartz systems have been investigated. Twelve North Sea crude oils were characterised with respect to asphaltene content and composition of saturates, resins and aromatics by the use of thin liquid chromatography. Acid and base numbers were measured for each crude oil. The acid numbers varied from 0.02 to 2.8, while the base numbers were in the range of 0.3 to 1.6.

One of the crude oils was separated into asphaltenes and deasphaltened oil, measuring acid and base number for both fractions. Based on different acid and base contents three of the oils were chosen for adhesion tests and contact angle experiments on quartz surfaces as a function of pH. These crude oils were also investigated with respect to interfacial activity.

The amount of acids and bases was found to be proportional to the amount of polars (NSO and asphaltenes). The acid and base numbers were correlated, meaning that a high acid number usually corresponded to a high base number. For the fractionated oil the deasphaltened oil was found to contain approximately equal amounts of acids and bases as the original crude oil. The results from contact angle measurements show more water wet surface at higher acid number, and more oil wet behaviour at higher base number. The interfacial tension of the crude oil/brine interface increased with increasing base/acid ratio.
Network Modeling to Predict the Effect of Wettability Heterogeneities on Multiphase Flow
Authors: Laroche C. , Vizika O. , Kalaydjian F.
Published: December 2007

In gas injection processes it has been already shown that the wettability characteristics of the solid surface and the spreading characteristics of the fluid system hold the key roles. Network modeling has proved to be a useful tool to phenomenological studies of multiphase flow. The objective of the present paper is to describe a network model of three- phase flow in porous media with heterogeneous wettability. Experimental support to validate the model is provided in the study by Laroche (SPE 52067) using micromodels with different wettability patterns.

The developed numerical tool is used to demonstrate the impact of small scale wettability heterogeneities on gas injection efficiency, for various patterns and spatial heterogeneity distributions. The model permits to impose heterogeneous wettability by assigning different water/oil contact angles according to the desired heterogeneity pattern. The initial distribution of oil and water in the network is established by simulating a two-phase displacement, which corresponds to a drainage in the water-wet region and to an imbibition in the oil-wet region. When gas is injected, three phases coexist within the network. The three-phase displacement is dominated by drainage mechanisms. Oil is assumed to flow through wetting films in the oil-wet regions and through spreading films on water in the water-wet regions. The simulations clearly demonstrate the effect of the size and distribution of wettability heterogeneities on water/oil displacement and three-phase gas injection. Also the effect of wettability heterogeneities distribution on water/oil capillary pressure is investigated by simulating quasi-static displacements.
Effect of Capillary Forces on Immiscible Displacement in Porous Media
Authors: Dong M. , Dullien F. A. L.
Published: December 2007

The complete fractional flow equation obtained previously by the authors from capillary models of both counter-current and co-current imbibition has been solved numerically, together with the mass conservation equation of water to obtain saturation profile histories in waterfloods in models of lengths ranging from lm to 200m, at an injection rate of 10−4cm/s. The saturation profiles change from near horizontal in the lm long model to near piston like in the 200m model. Equivalent roles are played by model length and by water injection rate in determining saturation profile history. Calculated saturation profiles match those determined in the laboratory when plotted against dimensionless distance coordinates. The complete and the simplified fractional flows, derived from calculated saturation profiles, have been compared: unlike the former ones, the latter are s-shaped curves. It is demonstrated with the help of the simple capillary model of imbibition that development of the Buckley-Leverett front under conditions when viscous forces dominate is nevertheless due to capillary forces. Capillary pressure gradient in the fractional flow equation can be neglected only at very low interfacial tensions when the relative permeability curves become straight lines. Multiple-valued saturation profiles are obtained from physically inconsistent simplified fractional flow equation in which the capillary pressure gradient is neglected but relative permeability data obtained under conditions of non-negligible capillarity are used.
A Simplified Approach to Geochemical Modeling and Its Effect on Well Impairment
Authors: Araque-Martinez A. , Lake Larry W.
Published: December 2007

Solids can easily cause impairment of wells by plugging flow channels. A source of these solids is the dissolution and subsequent precipitation of minerals caused by transport of fluids out of equilibrium with the host formation. To model these geochemical processes, allowing for the transport of fluids with kinetic reactions, it is necessary to solve the mass balance equations for each component flowing in the medium. This work presents a new approach, based on the method of characteristics (MOC), to greatly simplify these solutions. Based on this solution technique, we build a model that includes kinetic (aqueous-solid) as well as equilibrium (aqueous-aqueous) reactions. We define new dimensionless groups to scale the solution. Unlike many previous geochemical models, we focus on flow that is substantially out of local thermodynamic equilibrium.

The MOC model has been tested against results from the more general geochemical KGEOFLOW simulator and against experimental literature data. Results match the KGEOFLOW solution closely, but computing time is reduced at least 50 times. The MOC model can run quite general geochemical problems on a desktop personal computer. We applied the MOC model to a radial flow around a well to study the effect of precipitation, supersaturation, and dissolution on injection well impairment. We focussed on cases in which there was substantial well impairment in calculations based on local thermodynamic equilibrium. Results show that, at certain rates, a well's injectivity can be impaired, though the damage will be less severe than when local thermodynamic equilibrium is assumed. However, injection rates must be unrealistically large to completely prevent damage.
Calibrate Flow Simulation Models with Well-Test Data to Improve History Matching
Authors: He Nanqun , Chambers K. T.
Published: December 2007

In this paper we present a methodology to verify and update geostatistically based reservoir models using numerical simulation and automatic history matching of well-test data. A Bayesian estimation technique provides the framework for the inversion procedure used to update reservoir models. A restricted-step Gauss-Newton method and an extension of Carter's method for sensitivity coefficients make the methodology efficient and practical. Reservoir models (permeability, porosity and skin factor) can be updated based on individual simulation cells, geological feathers, or on constant multipliers applied in the well-test radius of investigation. When short-term well-test data is available from many wells, we found it useful to calculate property multipliers around each well and then interpolate the multipliers to unsampled areas in the reservoir.

Field examples demonstrate the utility of conditioning reservoir models with well-test data. In the examples, flowing bottomhole pressure mismatches are as high as 2000 psi and core based permeabilities deviate by two orders of magnitude from the well-test results. After conditioning to well-test data, pressure mismatches are significantly reduced, permeabilities are updated to the correct magnitude, and the skin factor closely matches the classic well-test analysis result.

We applied our updating methodology to a full-field simulation study on a large carbonate reservoir. Comparisons of historical pressure and production data to the updated full- field model demonstrate good agreement.
Effect of Pressure Uncertainty on Material-Balance Plots
Authors: Walsh Mark P.
Published: December 2007

Straight-line material-balance plots are routinely used to ana- lyze reservoir performance and estimate the OOIP and OGIP. Application necessarily requires average reservoir pressure measurements. Invariably, these measurements are subject to error. This paper presents a statistical analysis of the effects of pressure uncertainty on the practical applicability of these plots.

Results reveal that pressure uncertainty can drastically affect the reliability of certain plots. While all proposed plots are theoretically valid, certain plots are practically and categorically flawed because they require virtually error- free pressure measurements—a practical impossibility. The problem is further exacerbated by the observation that flawed and valid plots alike yield the same apparent linear character. This observation has lulled practitioners into a false sense of confidence that the flawed plots are meaningful and applicable. The plots are ultimately classified in terms of their error tolerance and sensitivity. The hypersensitive plots should be avoided.
A New Approach to the Analysis of Gas-Well Performance With Periodic Interruptions
Authors: Helmy M. Wael , Wattenbarger R. A.
Published: December 2007

This paper presents several techniques for the analysis of monthly production data of gas wells producing at constant bottomhole pressure from linear reservoirs, and subjected to periodic shut-ins. The frequent well interruptions cause severe scatter in the production data, which hinders the analysis using conventional methods: specialized-plots, deconvolution, etc...

We propose two different approaches to the analysis. First, we present an application of the superposition principle to identify an analytical reservoir model that gives a bottomhole pressure response similar to that observed in the field. The model is used to locate reservoir boundaries, calculate reservoir parameters and estimate the gas in place.

Second, we present a new analytical solution for the production rate following a shut-in period. The analytical solution is used to filter out the scatter in production data and establish the production trend had there been no production interruptions.

The first analysis technique is applicable to linear bounded reservoirs. However, the second method is limited only to linear infinite-acting reservoirs. Two field examples are given to illustrate the use and validity of the proposed methods.
Managing Uncertainties on Production Predictions Using Integrated Statistical Methods
Authors: Dejean J. P. , Blanc G.
Published: December 2007

Reservoir engineering requires to manage many sources of uncertainties that can be classified in two categories : (a) uncontrolled uncertainties on the physical reservoir description parameters and (b) controlled uncertainties on the reservoir development scheme parameters. In this context engineers must answer several problems : describe prior uncertainties, identify the ones that actually influence the oil production process, make safe production forecasts and optimize the reservoir production scheme.

In this paper, several statistical methods dealing with these problems are presented. They are (a) Experimental Design, (b) Response Surface Methodology and (c) Monte-Carlo methods. Integrating these techniques enables to build a simplified model of a process and to estimate the uncertainties on the response predictions. The entire procedure was applied to a field case showing both types of controlled and uncontrolled uncertainties. The result is a new frame allowing engineers to quantify uncertainties on the reservoir production forecasts conditionally to uncertainties on the reservoir modeling parameters. The procedure has lower computational costs than the traditional one but is quite complex and needs adapted software to be used by reservoir engineers.
Local Geomagnetic Field Modelling Closes the Gap Between MWD and Gyro Directional Surveying
Authors: Waag Tor Inge , Torkildsen Torgeir , Inderhaug Odd Helge , Carlsen Inge M.
Published: December 2007

A method for estimation of the influence of local geomagnetic anomalies on magnetic directional surveys has been developed. The method has been verified by comparisons between gyro and magnetic positioning.

The method relies upon aeromagnetic survey data, and estimates the 3 components of the local geomagnetic field along the wellpath from field data at flying altitude, and from downward continuation of the field data to reservoir depth. The field components can be predicted at depths down to the shallowest magnetic layer, and applied to enhance the accuracy of magnetic surveying. With access to core data the influence of magnetic material above the reservoir can also be included.

A comparison has been run with real magnetic and gyro data from 11 wells at 3 different fields offshore Norway. The results indicate a reduction in lateral position uncertainty by 50% typically. This is very significant when trying to hit small targets.

The method has been tested by major service companies and will soon be available as a part of their drilling services. This will benefit drilling with tight tolerances, especially in areas with large local magnetic anomalies such as the North Sea and Arctic regions. Local field strength anomalies can exceed 500 nanoTesla, declination errors can be more than 2 degrees and dip errors more than 0.5 degrees in these areas. The lateral position difference between magnetic and gyro surveying has been reduced from 20-50 m to 1-25 m in actual cases. The method has so far been applied in post-processing to verify the results, and is now being applied while drilling for correction of surveys.
Development for Acoustic Sensing System Ahead of the Bit for Detection of Abnormally High-Pressured Formation
Authors: Sugimura Yuzo , Masukawa Toru , Yonezawa Tetsuo , Hattori Shinichi , Taniguchi Ryosuke , Shimada Takashi
Published: December 2007

Japan National Oil Corporation, Technology Research Center (JNOC/TRC) Drilling and Completion Laboratory, has developed a technology which was able to measure formation velocity ahead of the bit in collaboration with Mitsubishi Electric Corporation.

In this paper, we are going to introduce you the research and development efforts enforced since 1996 to 1998 for establishing a sensor system to detect abnormal high-pressure zone while drilling. The system employs longitudinal elastic wave to detect formation boundary ahead of the bit, and measure formation velocity with distance to the boundary precisely. The system will give further prospect and detect abnormal high-pressure zone based on the formation velocities obtained there.
A New Platform for Attitude Determination and Declination Correction
Authors: Morsy Hatem , Estes Robert
Published: December 2007

Conventional directional measurement methods for MWD and Survey systems rely on measurement of the borehole orientation relative to the geomagnetic field. The borehole orientation can then be referred to the geographical coordinate system from the knowledge of the magnetic field orientation relative to True North and the horizontal plane. Calibration of the directional sensors relies on knowledge of the Geomagnetic Field intensity.

The geomagnetic field intensity is obtained annually from look up tables referred to as the British Geological Survey Model (BGSM) taken as a function of time and location. However, the Earth's Magnetic Field is not stable and may have noticeable, short term fluctuations due to diurnal variations, proximity to masses of magnetic material, local anomalies originating in the upper mantle, crust, or surface, and other phenomenon like solar activities. As a result, declination calculation and magnetic survey measurement will not be as accurate as they seem to be in most cases for the above mentioned reasons.

This new method is introduced to measure the local earth magnetic field, local magnetic dip angle, apparatus platform orientation with respect to the axis of the earth local magnetic field, the roll and tilt of that platform, and its longitudinal axis with respect to true north. This is done using the following combination of sensors: Inertial Motion Reference Unit (IMRU)tri-axial magnetometertri-axial accelerometerGlobal Positioning System (GPS) receiver antenna matrix.

Based on these measurements, an accurate declination calculation can be performed in real time. Thus, performing magnetic corrections and detection of magnetic anomalies can then be compensated. This is particularly critical in high latitude locations.

Very promising results were obtained through lab testing in Houston and Field Testing in Canada (the system shows excellent added value in high latitude locations).

This paper presents the results of the lab and field testing of the system that will be of great value to the drilling industry due to the enhanced accuracy provided by the system.
Dynamic Simulation of the Europa and Mars Expansion Projects: A New Approach to Coupled Subsea and Topsides Modeling
Authors: Lamey M. F. , Schoppa W. , Stingl K. H. , Turley A. J.
Published: December 2007

Accurate computational modeling of time-dependent flow in petroleum production systems - Dynamic Simulation - remains a crucial ongoing effort within Shell to identify and implement significant improvements in facility design and operation, particularly for Deepwater applications. To date, dynamic simulations of topsides processing facilities have been decoupled from flow transients in wellbores and subsea flowlines. An innovative approach to full-system dynamic modeling has been developed for the Mars Tension Leg Platform to accommodate production from the Europa Subsea Project that will utilize an existing topsides model and interface to an expanded topsides facility and subsea system flow model. The resulting simulation is unprecedented in scope and size, providing full thermal-hydraulic data from the sand face to the export pipelines. Despite the impressive scope of the model, its cost is reasonably low in relation to the total engineering effort. The dynamic interface consists of (i) OLGA simulation of transient multiphase flow in four subsea wells (with individual reservoir characteristics) and dual pipe- in-pipe insulated flowlines (20 mile offset), coupled to (ii) OTISS simulation of Mars topsides production equipment, including parallel compressor trains, multi-stage separators, oil export pumps, and numerous control valves, in addition to chemical injection umbilicals and well annulus vent facilities.

The principal goals of this integrated modeling approach were to identify, understand, and control unique transient operating conditions, including implications of varying field characteristics. Hence, this dynamic model is a powerful tool for (i) validating facility design, (ii) training of operations personnel (including elimination of surface/sub-surface communication barriers), and (iii) for optimization in surveillance planning. In fact, preliminary model results have revealed the necessity for some important modifications of facilities and operating procedures. Using the model in this fashion allows the engineer to reduce uncertainty factors in the design, which then lead to lower capital costs and/or operating expenses. A survey of the model's functionality is presented and discussed, including, but not limited to, well start-up and flowline blowdown.
The Effect of Side Arm Diameter on Phase Split at T-Junctions
Authors: Azzopardi B. J.
Published: December 2007

The effect of the ratio of side arm to mian pipe diameter on phase maldistribution during the division of gas/liquid flow at T-junctions is illustrated using data from experiments at two scales. The similarity and differences between data from different sources is highlighted. The ability of published models to predict the phase split is tested and possible sources of the shortcomings of the models are identified.
Advances in Liquid/Liquid Centrifuge Design Provide New Options for Petroleum Production
Authors: Meikrantz D. H. , Macaluso L. L. , Flim W. D. , St. George M. M.
Published: December 2007

Recent advances in liquid-liquid centrifuge design coupled with experience gained in separating water from oil and oil from water provides a powerful, new option for petroleum production. The annular centrifugal contactor is a vertical, liquid-liquid, direct drive, low speed centrifuge that is capable of both mixing and separating in a single unit. Further design improvements which enhance this centrifuge's utility and efficiency in two-phase liquid separation are a low mixing sleeve and a clean-in-place rotor. Using the low mix mode, oil in water concentrations at the centrifuge outlet are typically in a range of 20 to 200 ppm, dependent upon the process conditions. Water in oil levels of less than 1% can be reached in heavier oil stocks and are even lower for light crudes and refined products. This new design is capable of processing input oil-water ratios which vary from 0–100% without adjustment. This important advancement is possible because, in this design, the oil-water interface can shift position within the separating zone of the rotor without causing a loss of separation quality. A clean-in-place (CIP) option consisting of numerous spray nozzles installed in the rotor's central hollow shaft is employed to deliver a cleaning solution to the inside diameter wall for rapid and efficient solids removal. The entire process can be automated to clean multiple centrifuges, sequentially, requiring only five minutes per unit. Examples of applications for this technology include; single stage oil dehydration, de-oiling process water, desalting of oil via washing, and other custom liquid-liquid processes.
Capillary Pressure and Rock Wettability Effects on Wireline Formation Tester Measurements
Authors: Elshahawi H. , Fathy K. , Hiekal S.
Published: December 2007

Wireline formation testers such as the well established Repeat Formation Tester (RFT™) and the more recent Modular Dynamics Tool (MDT™) measure the pressure of the continuous phase present in the invaded region, which is typically drilling fluid filtrate. Conventional interpretation techniques have often assumed this pressure identical to the pressure of the continuous phase in the virgin region of the formation, i.e., formation fluid pressure. As such, a series of pressure measurements at different depths would be expected to consistently yield a pressure gradient corresponding to the density of the formation fluid. More recent work has pointed out that this assumption cannot be entirely correct, otherwise it would appear that most formation tester surveys are anomalous.

In reality, because the concepts of free fluid level, fluid contacts, rock wettability, and pore fluid pressures are so intimately related, the measured tester pressure cannot be simply identical to formation pressure. Rather, it is different from the formation fluid pressure by the amount of capillary pressure, which is itself mainly a function of the wetting phase saturation. The effects of rock wettability and capillary pressure on wireline formation tester measurements are often manifested in one or both of two ways:

Fluid level changes, which affect the position of the free water level with respect to the fluid contacts determined from other openhole logs. Gradient changes, which affect the slope and scatter of the gradient lines.

This paper explores the effects of capillary pressure and formation wettability on wireline formation tester measurements and investigates ways of correcting or compensating for these effects.
Completion Selection Methodology for Optimum Reservoir Performance and Project Economics in Deepwater Applications
Authors: Wetzel R. J. , Mathis Steve , Ratterman Gene , Cade Randall
Published: December 2007

This paper represents two main areas: (a) the interface between the wellbore and reservoir and the role of completion design in ensuring optimum reservoir exploitation, and (b) the risks inherent in various completion options as evaluated using current risk analysis techniques.

Unique characteristics of various completion options will be presented and compared with regard to their impact on well productivity, cycle time and reliability. Case studies from the Gulf of Mexico and other deepwater environments are referenced to illustrate how the completion design impacts project economics, net present value and time to break-even.

Risk analysis will be applied to well types to illustrate the potential savings in operating expense and overall completion cost.
Determining Fracture Closure Pressure In Soft Formations Using Postclosure Pulse Testing
Authors: Upchurch E. R.
Published: December 2007

This paper discusses the theory and application of a pressure pulse testing technique for use in determining fracture closure pressure (Pc) in soft formations. This technique is intended for use after a data-frac has been pumped, and then only after the fracture is closed. Implementing the pulse technique postclosure, rather than while the fracture is still open, allows it to be used as an independent determination of Pc without diminishing the accuracy of the fluid leakoff coefficient (CL) determined from the data-frac. Previous pulse testing techniques1 require pumping into a fracture while it is still open. This practice reduces the accuracy of CL by altering the time necessary for the fracture to close (tc). Furthermore, previous pulse testing techniques yield only a range of possible Pc's, whereas the postclosure pulse technique yields a better defined, singular value of Pc.

The accuracy of postclosure pulse testing is validated using several field examples from a soft formation on Alaska's North Slope by comparing definitive Pc's determined using pressure decline analysis with Pc's determined from postclosure pulse testing.
Understanding Hydraulic Fracture Growth: Tricky but Not Hopeless
Authors: Wright C. A. , Weijers L. , Davis E. J. , Mayerhofer M.
Published: December 2007

Hydraulic fracturing has proven to be a fruitful well stimulation technique in an ever-increasing range of environments. Application has spread from the original target of enhancing production rates from low permeability reservoirs to fracturing of poorly consolidated high perm reservoirs, fracturing of horizontal and deviated wellbores, fracturing of unconventional (often naturally fractured) reservoirs, fracturing for waste disposal, etc. While significant progress has been made in engineering hydraulic fracturing treatments, we are still often humbled and alarmed by the apparent complexity of the process.

This paper does not present "the answer" to this complex problem. Instead it attempts to shed some light on areas where we must be careful with our assumptions. This paper presents examples of measuring (inferring) hydraulic fracture growth in a number of different environments. For each example we discuss the implications of the observed fracture growth. For example, how accurate were the fracture model predictions? How effective is the current completion / fracturing strategy in achieving the design goals? What are we learning about the factors or mechanisms that govern hydraulic fracture growth? How can these new insights aid production enhancement?

While most of the direct observations of hydraulic fracture growth are from downhole-tilt fracture mapping, data from many additional diagnostics are also included (post-frac logging, production response, intersections with offset wells, microseismic mapping, etc). Perhaps the most surprising observation is the observed range of fracture height growth: spanning from well-contained fractures in the absence of significant formation stress barriers, to extremely uncontained fracture height growth. Observations of fracture width, length, and asymmetry will also be presented and discussed.
Reconciling Time-lapse Seismic Data and Production Data: Application to a Gas Field
Authors: Huang Xuri , Will Robert , Khan Mashiur , Stanley Larry
Published: December 2007

In general, integration of time-lapse seismic and dynamic data requires extensive work to build a "common" earth model1,2 honoring both types of data. This typically leads to longer turnaround times for time-lapse seismic projects. This paper demonstrates a method to shorten this time by reconciling production data with time-lapse seismic data in the data domain rather than in the earth model domain. The results from this method demonstrate that this quick evaluation can reveal whether or not the observed seismic differences represent reservoir changes associated with production, and can provide a basis for a more extensive model based evaluation. This method was applied to a gas reservoir in the Gulf of Mexico where preliminary rock physics modeling showed that water replacement would lead to more than 10% impedance change for approximately 30% of gas saturation change. Model fluid substitution studies using an approximation of the local geologic setting yielded seismic impedance changes significantly lower than those observed in field measurements. This discrepancy is demonstrated through further model studies to be the result of thin bed tuning. Rebinning and cross-equalization with time-varying crosscorrelation were applied to normalize the 1987 and the 1995 3D seismic volumes. The seismic difference map was then transformed into a calibrated gas volume through reconciliation of fluid production volumes with seismic difference volumes. The saturation-amplitude relation used to threshold the seismic difference volume was calibrated at well locations. These results were validated using material balance and production data analysis to reconcile engineering data with base and monitor seismic survey volumes. Hence, the final difference map maximizes the probability that the seismic differences are representative of saturation changes in the reservoir. This work: (1) provides a new procedure for gas reservoir time-lapse analysis under certain geological conditions and production mechanism; and (2) demonstrates a new first order method to reconcile time-lapse seismic data and production data without employing time consuming reservoir characterization and flow simulations. This approach greatly reduces the turnaround time involved in use of time-lapse seismic information for reservoir management. Further, the result could lead to better subsequent model based analyses1,2. This work also shows that seismic tuning effects need to be taken into account when relating petrophysical changes to seismic amplitude differences in time-lapse seismic studies.
Principal Component Analysis Applied to 3D Seismic Data for Reservoir Property Estimation
Authors: Scheevel J. R. , Payrazyan K.
Published: December 2007

We apply a common statistical tool, Principal Component Analysis (PCA) to the problem of direct property estimation from 3D seismic amplitude data. We use PCA in a novel way with the purpose of deriving detailed reservoir property predictions from a channellized sand and shale reservoir that is further complicated by faulting.

In order to apply PCA methods to a single-property, 3D-seismic amplitude volume, we sample the volume with a small sliding sampling window that captures multiple, vertically adjacent amplitude samples as a vector. The sampled vectors from all such windows in the seismic dataset forms the set of input vectors for the PCA algorithm. Final output from the PCA algorithm is a cube of assigned classes of clustered Principal Components (PC's). The clusters are used as a categorical variable when predicting reservoir property away from well control.

We evaluate the effectiveness of our method by applying a crossvalidation technique, alternatively withholding each of the three wells drilled in the area, and computing predicted effective porosity (PHIE) estimates at the withheld location by using the remaining two wells as "hard" data. This process is repeated three times, each time excluding only one of the wells as a blind control case. In each of the three blind control wells, our method predicts accurate estimates of vertical sand/shale distribution, and the effective porosity-thickness product values. The method properly predicts a low sand-to-shale ratio at the blind well location, even when the remaining two "hard" data wells contain only high sand-to-shale ratios.

Good predictive results from this study area make us optimistic that this method is valuable for general reservoir property prediction from 3D seismic data, especially in areas of rapid lateral variation of the reservoir. We feel that this method of predicting properties from the 3D seismic is preferable to traditional, solely variogram-based, geostatistical estimation methods. Such traditional geostatistical methods have difficulty capturing the detailed distribution of the lithologies when limited by sampling bias of the hard data control. This problem is especially acute in areas where rapid lateral geological variation is the rule. Our method effectively overcomes this limitation because of the strong estimation constraint offered by the PCA-processed and calibrated 3D seismic data.
Pore-Scale Study of the Flow of Oil and Water through Polymer Gels
Authors: Al-Sharji Hamed H. , Grattoni Carlos A. , Dawe Richard A. , Zimmerman Robert W.
Published: December 2007

High water production is one of the major problems faced by the petroleum industry. One method of controlling water production that has been used with some success is to inject polymer gels into the near-well bore formation. However, polymer gel injections are not always successful, in part because the exact mechanisms by which they reduce water permeability more so than oil permeability are not understood.

To elucidate the fundamental mechanisms involved in disproportionate permeability reduction (DPR), we have conducted a series of experiments on flow of water and oil through bulk polymer gels and through polymer-filled glass micromodels. Flow experiments through weak polyacrylamide-based gels have been performed to obtain the gel permeabilities by using different test conditions: constant pressure, constant flow rate, and the falling head method. Gel permeability was found to vary with flowrate, according to a power-law that holds over several orders of magnitude of velocity. This was true for both water and oil flow, although with different pre-factors and exponents.

Water flows through the gel matrix as if flowing through a porous medium, whereas the oil pushes its way through in the form of immiscible drops or filaments. Mathematical models to quantify these flows are currently being developed.
Water Shutoff by Relative Permeability Modifiers: Lessons from Several Field Applications
Authors: Zaitoun A. , Kohler N. , Bossie-Codreanu D. , Denys K.
Published: December 2007

IFP water shutoff technology is based on the use of relative permeability modifiers (RPM's). The technique consists of bullhead injection of polymer solutions into existing completions, usually without zone isolation. The polymer can be swelled or weakly crosslinked in situ to increase permeability reduction to water. The chemistry of the different processes is explained. Each process covers a specific domain of temperature and salinity. All systems are designed to affect oil or gas relative permeability only slightly.

By reviewing typical field cases, i.e. water shutoff in gas storage wells, heavy-oil horizontal wells, offshore gravel-packed wells and multilayer-waterflooded wells in both sandstone and limestone reservoirs, several guidelines are presented, dealing with candidate well selection, process design, operational aspects and treatment evaluation. Crucial for a successful treatment is the placement of the chemicals. Therefore in order to make RPM treatments more reliable, future focus of research should be oriented towards diversion aspects. Some solutions are suggested and discussed.
Mechanistic Reservoir Modeling Improves Fissure Treatment Gel Design in Horizontal Injectors, Idd El Shargi North Dome Field, Qatar
Authors: O'Brien William J. , Stratton J. Jay , Lane Robert H.
Published: December 2007

The first polymer-gel water control treatment for Occidental Petroleum of Qatar Ltd. was pumped in Idd El Shargi North Dome (ISND) Shuaiba Well B in April 1998. The treatment program was optimized for a jack-up drilling rig based operation and pumped after encountering a conductive fault zone at 8400′ MD that had resulted in total losses. The total volume pumped was 13790 bbls with a sustained pump rate of 12 BPM. Downhole pressure response from real time gauges during the treatment indicated that the gel had entered a large void space. When drilling commenced after the treatment, there were full returns. Although the treatment was successful, a very large volume had been pumped. To help minimize the costs of future treatments, further optimization would be required via reservoir modeling.

A finely gridded mechanistic two-well pattern model of the "A" and "B" intervals of the Shuaiba reservoir was built to optimize the design of polymer-gel treatments in horizontal wells of the ISND field. The Shuaiba reservoir is a low permeability, argillaceous carbonate containing numerous highly conductive faults. This model attempted to emulate these treatments by isolating a conductive fault at the injector from top to bottom of the "A" and "B zones. Three fault permeabilities were considered for this model: 250 md, 500 md and 1500 md.

Waterflooding is planned for this reservoir to replace reservoir voidage and improve oil recovery. Since the numerous conductive faults in the ISND field are anticipated to reduce waterflood sweep efficiency, treatments to plug these faults are anticipated to become an integral part of the waterflood development.
A Novel Non-Iterative Method for the Prediction of the PVT Behavior of Reservoir Fluids
Authors: Varotsis N. , Gaganis V. , Nighswander J. , Guieze P.
Published: December 2007

This paper presents a novel approach for the prediction of the complete PVT behavior of reservoir oils and gas condensates. The method uses key measurements that can be performed rapidly either in the lab or at the well site as input to an Artificial Neural Network (ANN) architecture. The ANN architecture has been trained by a PVT studies database of over 650 reservoir fluids originating from all parts of the world.

Tests of the trained ANN architecture utilizing a validation set of PVT studies indicate that, for all fluid types, most PVT property estimates can be obtained with a very low mean relative error of 0.5–2.5%, with no data set having a relative error in excess of 5%. This level of error is considered better than that provided by tuned Equation of State (EOS) models, which are currently in common use for the estimation of reservoir fluid properties. In addition to improved accuracy, the proposed ANN architecture avoids the ambiguity and numerical difficulties inherent to EOS models and provides for continuous improvements by the enrichment of the ANN training database with additional data.

The developed model has been named PVT Expert*, and is shown to be a robust, accurate and quick prediction tool that can be used for estimating reservoir fluid properties over the entire range of operating conditions and fluid types. The main application of the model is envisaged to be the rapid generation of PVT data based on field generated measurements. The results show that these reports will be of comparable accuracy to a full PVT study generated in the laboratory. In addition to this, other applications are seen in providing accurate estimates of physical properties for use in well test validation and reservoir/production engineering calculations as well as providing for the quality assurance of laboratory generated fluid property data.
Predicting Reservoir Fluid Phase and Volumetric Behaviour from Samples Contaminated with Oil-Based Mud
Authors: Gozalpour F. , Danesh A. , Tehrani D. -H. , Todd A. C. , Tohidi B.
Published: December 2007

Oil based muds are widely used in offshore drilling applications. Of concern however is the resulting contamination associated with obtaining high quality samples of formation hydrocarbons. The filtrate of oil based muds is highly soluble in formation hydrocarbon fluids, therefore, any contamination of the sample with oil based mud filtrate can significantly affect the composition and phase behaviour of the formation fluids.

In this study the impact of contamination on the phase behaviour and properties of different types of reservoir fluids, including gas condensate and volatile oil samples, is investigated. Various types of oil based muds, synthetic (with limited number of hydrocarbons) and natural oil (wide range of petroleum fractions), are used to contaminate reservoir fluids and their composition and phase behaviour are measured at surface and reservoir conditions in this laboratory. Two simple methods have been developed to determine the uncontaminated fluid composition from contaminated samples. Highly contaminated field samples have been used to demonstrate the capability of the developed methods.

The phase behaviour and volumetric properties of the original reservoir fluid predicted by phase behaviour models developed for contaminated samples can highly be erroneous. A method has also been developed in this study which can determine the required equation of state (EOS) parameters of the uncontaminated fluid, using the developed phase behaviour models from data of contaminated samples. The capability of the method has been examined against experimental data of different types of reservoir fluids. The proposed method in all cases provided accurate predictions of PVT data. The developed method is general and it can be applied to any cubic EOS.
Estimating Relative Permeability from Production Data: A Streamline Approach
Authors: Kulkarni Kari Nordaas , Datta-Gupta Akhil
Published: December 2007

One of the outstanding challenges in reservoir characterization is to build high-resolution reservoir models that satisfy static as well as dynamic data. Integration of dynamic data so far has mainly focused on estimating spatial distribution of absolute permeability. Among the various properties important for simulating reservoir behavior, the relative permeability curves may be by far the most poorly determined by present methods. Estimation of relative permeability simultaneously with absolute permeability is a strongly nonlinear and ill-posed estimation problem.

In this paper we present a streamline-based approach for estimating relative permeabilities from production data. The streamline approach offers two principal advantages. First, we can analytically compute the sensitivity of the production response with respect to relative permeability parameters. The approach is extremely fast and requires a single streamline simulation run. Second, we can exploit the analogy between streamlines and seismic ray tracing to develop a formalism for efficient inversion of production data. Thus, estimation of relative permeabilities is carried out in two steps: (i) matching of breakthrough or first arrival times and (ii) matching of amplitudes of the production response.

For relative permeability representations we have used the commonly used power functions and also a more flexible representation through the use of B-splines. The relative advantages of these representations are examined through inversions of water-cut data from a nine-spot pattern. Finally, we address the underlying challenges associated with the simultaneous estimation of absolute and relative permeabilities from production data. We systematically investigate the non-uniqueness associated with the inverse problem and quantitatively evaluate the role of additional data such as pressure response in addition to water-cut history at the wells.
Fully Coupled Analysis of Improved Oil Recovery by Reservoir Compaction
Authors: Chin L. Y. , Thomas L. K.
Published: December 2007

The combined effect of stress, fluid flow, and reservoir property changes on oil recovery were evaluated by a fully coupled procedure that integrates geomechanics and reservoir simulation. In this development, we pay particular attention to changes in oil recovery caused by reservoir compaction (the so-called compaction drive mechanism) and to the impact of the constitutive behavior of rock deformation on oil recovery. In general, for weak hydrocarbon reservoirs that exhibit nonlinear, elastic and plastic constitutive behavior, the coupling effect may not be ignored in reservoir simulation. The coupled interaction between geomechanics and reservoir fluid production significantly affects the stress state, reservoir properties, and the efficiency of oil recovery. Both fully and loosely coupled methods are used to illustrate the impact of reservoir compaction on oil recovery. The key variables investigated, that are important in improving oil recovery by the compaction drive mechanism, include the constitutive behavior of reservoir rock, the water-weakening effect, stress-dependent permeability, and the overburden/reservoir interaction. The numerical results from this study show that a fully coupled geomechanics and reservoir simulation approach can be used to accurately quantify the economic impact of compaction drive, and the coupled numerical procedure employed in this paper provides such a tool. A comparison between the fully and loosely coupled models is given.
Estimation of Leakoff Pressure Gradient from Cementing and Casing Data
Authors: Zhou D. , Wojtanowicz A. K.
Published: December 2007

The paper describes the development and use of a new procedure for finding safe value of casing shoe leak-off pressure in surface holes in the shallow-marine sediments (SMS). Presented is a theoretical proof, supported by field data from leak-off tests, that, in SMS, annulus channeling outside cement occurs more likely at pressure values smaller than the rock fracturing pressure. Hence, for upper well sections in SMS the prediction of casing shoe strength should be based on critical conditions for annulus channeling rather than rock fracturing.

It is also shown that pressure required for casing shoe leak-off behind cement can be determined from contact stress between cement and wellbore. Contact stress develops during the process of cement setting as a result of volumetric changes in the annulus. Set up is a mathematical model of contact stress around casing shoe based on cement volume reduction and compensation from casing string, cement compressibility and wellbore. Using readily available data of well geometry, casing properties and cementing operation, simple procedure, explained in this paper, gives a good estimation of cement fracture compared with actual leak-off test values.

The study identifies two factors, related directly to drilling technology, that control critical pressure of cement channeling in SMS: contact stress at casing shoe – resulting from cementing operations, and rock penetration by liquid – an invasion of drilling fluid into the rock around the casing shoe. It is shown in the paper that changes in cementing and drilling practices may increases casing shoe integrity and reduce the need for cement squeeze treatments.