bluuebunny/crossref_metadata_2025_split huggingface dataset:
Capillary Pressure and Rock Wettability Effects on Wireline Formation Tester Measurements
Authors: Elshahawi H. , Fathy K. , Hiekal S. 
Published: December 2007

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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.