bluuebunny/crossref_metadata_2025 huggingface dataset:
Lessons Learned From Energy Models: Iraq's South Rumaila Case Study
Authors: Kabir C. S , Al-Khayat N. I. , Choudhary M. K.
Published: March 2009

Understanding reservoir behavior is the key to reservoir management. This study shows how energy modeling with rapid material-balance techniques, followed by numerical simulations with streamlines and finite-difference methods, aided understanding of reservoir-flow behavior. South Rumaila's long and elongated Zubair reservoir experiences uneven aquifer support from the western and eastern flanks. This uneven pressure support prompted injection in the weaker eastern flank to boost reservoir energy.

We learned that aquifer influx provided nearly 95% of the reservoir's energy in its 50-year producing life, with water injection contributing less than 5% of the total energy supply. The west-to-east aquifer energy support is approximately 29:1, indicating the dominance of aquifer support in the west. Streamline simulations with a 663,000-cell model corroborated many of the findings learned during the material-balance phase of this study. Cursory adjustments to aquifer properties led to acceptable match with pulse-neutron capture or PNC-derived-time-lapse oil/water contact (OWC) surfaces. This global-matching approach speeded up the history-matching exercise in that performance of most wells was reproduced, without resorting to local adjustments of the cell properties. The history-matched model showed that the top layers contained the attic oil owing to lack of perforations.

Lessons learned from this study include the idea that the material-balance work should precede any numerical flow-simulation study because it provides invaluable insights into reservoir-drive mechanisms and integrity of various input data, besides giving a rapid assessment of the reservoir's flow behavior. Credible material-balance work leaves very little room for adjustment of original hydrocarbons in place, which constitutes an excellent starting point for numerical models.
Improved Understanding of Reservoir Fluid Dynamics in the North Sea Snorre Field by Combining Tracers, 4D Seismic, and Production Data
Authors: Huseby O. , Andersen M. , Svorstøl I. , Dugstad Ø
Published: March 2009

To obtain improved oil recovery (IOR), it is crucial to have a best-possible description of the reservoir and the reservoir dynamics. In addition to production data, information can be obtained from 4D seismic and from tracer monitoring. Interwell tracer testing (IWTT) has been established as a proven and efficient technology to obtain information on well-to-well communication, heterogeneities, and fluid dynamics. During such tests, chemical or radioactive tracers are used to label water or gas from specific wells. The tracers then are used to trace the fluids as they move through the reservoir together with the injection phase.

At first tracer breakthrough, IWTT yields immediate and unambiguous information on injector/producer communication. Nevertheless, IWTT is still underused in the petroleum industry, and data may not be used to their full capacity—most tracer data are used in a qualitative manner (Du and Guan 2005). To improve this situation, we combine tracer-data evaluation, 4D seismic, and available production data in an integrated process. The integration is demonstrated using data from the Snorre field in the North Sea. In addition to production data, extensive tracer data (dating back to 1993) and results from three seismic surveys acquired in 1983, 1997, and 2001 were considered.

Briefly this study shows that

Seismic and tracer data applied in combination can reduce the uncertainties in interpretations of the drainage patterns. Waterfronts interpreted independently by tracer response and seismic dimming compare well. Seismic brightening interpreted as gas accumulation is supported by the gas-tracer responses.
Fluid-Loss Control Improves Performance of Viscoelastic Surfactant Fluids
Authors: Huang Tianping , Crews James B.
Published: March 2009

Viscoelastic surfactant (VES) fluids have been widely used as gravel-packing, frac-packing and fracturing fluids for more than a decade because the fluids exhibit excellent rheological properties and maintain low formation-damage characteristics compared with crosslinked-polymer fluids (Nehmer, 1988; Brown et al. 1996). Because of its non-wall-building property, VES fluid has much higher fluid leakoff into the reservoir matrix than wall-building polymer fluid. For frac-packing, this high-leakoff property has limited VES fluid's application to reservoirs with permeability of less than 400 md. Excessive fluid leakoff also significantly increases the cost of treatment.

This paper will introduce new technology for controlling the fluid loss of VES fluids to approximately 300°F. New fluid-loss control agents have been developed that, through chemisorption and surface-charge attraction, associate with VES micelles to produce a pseudo-filter-cake of viscous VES fluid that significantly reduces the rate of fluid loss. Use of this technology will reduce the VES fluid volume required for a given treatment by up to two-thirds and extends the permeability range of VES fluids to approximately 2000 md. The fluid-loss control agents are tiny particles that are used at relatively low concentrations. The tiny particles will be flowed back with the production fluid after VES micelles are broken by internal breakers. The rate of the pseudo-filter-cake cleanup is enhanced by use of internal VES breakers. The results of rheology, leak-off, and core flow tests will be presented for the VES fluid systems at temperatures 150°F and 250°F.
Data Mining Identifies Production Drivers in a Complex High-Temperature Gas Reservoir
Authors: Shelley Bob , Harris Phillip C.
Published: March 2009

This paper presents the results of a data-driven, field-modeling (DDFM) evaluation applied to a high-temperature reservoir in Australia for the purpose of determining the significance of chemistry, reservoir, well, and hydraulic-fracture characteristics on well production. The DDFM approach has identified key production drivers for a gas-well field in Australia. This information has been useful in explaining hydraulic-fracture well production and providing guidelines for future fracture stimulation success.

A DDFM process is used to develop a model for 32 wells completed in a complex, 250 to 350°F gas reservoir in Australia. This type modeling technique uses data from the field, including chemical formulation, geology, reservoir, well, completion, hydraulic-fracture stimulation, and production results. The data is integrated into a common format and resolution, and then a visual and statistical evaluation is performed. Relevant correlations and useful trends are noted. Next, an effort is made to develop a predictive model that can be used to provide an overall explanation as to what parameters drive production in the well field. Or, in effect, derive a high-level understanding about the effect of the fracturing process on the reservoir. This is accomplished by the use of data modeling/optimization technologies, including artificial neural network (ANN) and genetic algorithms. The resulting ANN model can then be used to evaluate the production associated with various hydraulic-fracturing scenarios and/or characteristics. Validation of conclusions and/or resolution of difficult interpretation issues are done by detailed evaluation and modeling of key wells.

Hydraulic-fracture stimulation scenario evaluations performed by the ANN model have yielded some expected as well as unexpected results. As expected, reservoir characteristics, such as pay thickness, porosity, and water saturation have a dominant effect on well production. What was unexpected is the significance of well operations and stimulation fluid chemistry on well production. The practice of killing the well after stimulation and using inappropriate perforation techniques can reduce gas production by as much as one-half, while the use of a high-temperature gel breaker in combination with a reduction in base-gel polymer load can provide a 67% increase in production.
Feasibility Study of Ultrasound for Oil Well Stimulation on the Basis of Wave-Properties Considerations
Authors: Caicedo Sergio
Published: March 2009

Ultrasound or a high-frequency (20 kHz to 100 kHz) pressure wave has been used in diagnosis and treatments in different areas, such as: medicine, dentistry, civil engineering, and many other industrial applications. In the oil industry, there are applications (i.e., pipeline inspections, fluid velocity measurements, etc.), but to the present, these applications in formation stimulation have been incipient, and only a few lab and field test experiences have been reported. Stimulation with ultrasound is not a common operation offered by oil service companies. To visualize the real potential of ultrasound in oil well stimulation, it is necessary to understand the wave phenomenon, its properties, the parameters that define its behavior, and its interaction with the propagation media. This basic knowledge and the understanding of the different formation damage mechanisms are the keys to comprehend the real potential and application window of the ultrasound in oil well stimulation. This paper presents the theoretical basis of ultrasound and wave phenomena that must be considered when considering stimulation with ultrasound. Finally, some suggestions about the application window of this technology are given.
Placement of Permanent Downhole-Pressure Sensors in Reservoir Surveillance
Authors: Izgec B. , Cribbs M. E. , Pace S. V. , Zhu D. , Kabir C. S.
Published: March 2009

This paper probes the gauge-placement issue with regard to yielding quality formation parameters unaffected by wellbore effects. Nonphysical or biased results may result if the wellbore effects are unaccounted for.

We used a wellbore/reservoir simulator that conserves mass, momentum, and energy to develop a comprehensive understanding of the gauge-placement issue. First, we reproduced a field example from a deepwater asset to demonstrate the simulator's capabilities. In this example, we matched the bottomhole pressure (BHP) and pressure/temperature monitored about midpoint of the flow string during a multirate-test sequence lasting approximately 60 hours. Calculations show that thermal effects are exacerbated by increasing flow rate and increasing gauge distance from the perforations.

Second, we performed a detailed uncertainty analysis with experimental design. Variables included in this analysis were perforation-to-gauge distance, permeability, geothermal gradient, flow rate, fluid viscosity, thermal conductivity of annular fluid and formation, and mechanical skin. This analysis sheds light on relative importance of these variables on our ability to extract formation parameters. Simple correlations are developed for designing gauge placement in many environments.
Hydraulic Fracturing With Heated Fluids Brings Success in High-Pour-Point Waxy-Oil Reservoir in India
Authors: Shaoul Josef , Spitzer Winston , Ross Michael , Wheaton Stuart , Mayland Paul , Singh Arvinder Paul
Published: March 2009

Most existing production of waxy oils occurs in high-permeability formations, and wax issues are mostly a problem in the production tubing or pipeline. Large reserves also exist in low-permeability formations that require hydraulic fracturing for economic production. Such a reservoir was recently discovered in Rajasthan, northwest India, overlying a more typical high-permeability formation, both with high-pour-point waxy oil. Because a very large amount of oil in place is present in the low-permeability formation, two fracturing campaigns were performed in two different horizons to assess the potential for successful well stimulation. The first fracturing campaign (on four wells) showed limited success. A study was performed to determine the reason for the failure, and significant changes were made for the second campaign. This paper documents the second campaign. This campaign featured the first successful use in India of heated fluids to stimulate a shallow, low-permeability, massive oil reservoir containing high-pour-point waxy oil.
Quantitative Analysis of Reaction-Rate Retardation in Surfactant-Based Acids
Authors: Nasr-El-Din H. A. , Al-Mohammad A. M. , Al-Aamri A. D. , Al-Fahad M. A. , Chang F. F.
Published: March 2009

Fracture acidizing has been a dominant practice in the industry to enhance well productivity in low-permeability carbonate reservoirs. Many acid systems have been developed to improve this stimulation process. The most desirable characteristics for an acid system to be suitable for fracture acidizing are leakoff control and retarded reaction rate. These characteristics are required for deep acid penetration, so that when the fracture closes, long flow channels are etched on the fracture surfaces. Leakoff control can be achieved by pumping a pad containing a viscosifying agent or solid bridging agents to plug wormholes generated by acid dissolution. Reaction retardation is attempted usually by lowering the effective diffusivity of the hydrogen ion.

It is well known that during an acid-fracturing operation, the overall reaction rate of hydrochloric acid (HCl) with limestone is mass-transfer-limited. Designing the treatment requires knowing the effective diffusivity of the hydrogen ion in the acid system, which, to the best of the authors' knowledge, has not been determined before. Because of their combined leakoff-control and retardation capabilities, surfactant-based acids have been used in acid-fracturing treatments. Because more carbonate reservoirs are treated by use of this acid system, it is important to obtain the effective diffusivity of H+.

The rotating-disk device has been used to investigate the reaction kinetics between a reactive solution and carbonate rocks because the thickness of the boundary layer is uniform throughout the disk surface. This paper discusses the reaction-rate data generated recently for surfactant-based acid by use of a rotating-disk apparatus and presents the methodology used to determine the effective diffusivity from the measurements.

The results obtained indicated that the viscoelastic surfactant examined (carboxybetaine-type) reduced the dissolution rate of calcite with HCl acid. The surfactant reduced the diffusion coefficient for H+. The effect of temperature on the diffusion coefficient did not follow the Arrhenius law.
The Effect of Residual Oil on Deep-Bed Filtration of Particles in Injection Water
Authors: Ali Mohammad A. J. , Currie Peter K. , Salman Mohammad J.
Published: March 2009

Production of hydrocarbons is usually accompanied by the production of water. This produced water consists of formation water and/or water that has previously been injected into the formation. As more oil is produced, the amount of produced water increases. Unfortunately, the produced water is not a saleable product; hence an operator must find ways to handle relatively large amounts of water in an environmentally-acceptable manner at the lowest cost. One way of managing this water is to re-inject it for disposal, pressure maintenance, or enhanced oil recovery. An important and difficult task in the re-injection process is the prediction of the impact of water quality on well injectivity. This is mainly because of the poor understanding of the deposition mechanisms by which suspended solids and oil droplets present in the produced water are retained by the formation.

As part of a study on formation damage, different concentrations of hematite particles suspended in water were injected into sandstone core samples at residual oil saturation. The theories of deep-bed filtration are evaluated. The effects of residual oil on the filtration coefficient λ and the formation damage factor β are examined. The presence of oil caused greater apparent damage (reduction of permeability). It was also observed that there is rather deeper invasion at residual oil saturation than at full brine saturation.
Application of Cationic Surfactant-Based Fluids for Acid Diversion
Authors: Nasr-El-Din H. A. , Al-Nakhli A. R. , Al-Driweesh S. M. , Welton T. , Sierra L. , Van Domelen M.
Published: March 2009

This paper examines the use of surfactant gels during matrix acid treatments and describes field trials of these fluids. Unlike available viscoelastic surfactants used today in the field, this surfactant is cationic. If used in live acids, the fluid has a relatively low viscosity when pumped. Once the acid is spent, however, the surfactant molecules increase its viscosity significantly. To enhance diversion further, the acidic fluids or brines can be foamed with this surfactant.

Rheological measurements were conducted on Hastelloy®- fitted rotational viscometers at temperatures ranging from 70 to 300°F. The effects of surfactant concentration, shear rate, temperature, and acid additives on the apparent viscosity of various surfactant-based fluids were investigated in detail.

The surfactant was stable thermally and hydrolytically with most acid additives. While it was compatible (i.e., still formed a viscosifying gel), some additives adversely affected the apparent viscosity of surfactant solutions at a given temperature. The apparent viscosity of surfactant solutions increased with salt concentration and can be predicted by use of the Carreau-Yasuda model. Coreflood tests indicated that the surfactant delayed acid breakthrough in calcite cores. Acceptable corrosion rates were obtained when this surfactant was added to the acid.

The performance of this surfactant was validated with field treatments. The surfactant was used in more than 100 matrix acid treatments (oil producers and water injectors). It was used to increase the viscosity of acids in situ and enhance the stability of foams used for diversion. All wells responded positively to these treatments, and no operational problems were encountered. Downhole gauges confirmed the ability of surfactant-based fluids to divert the acid into various zones.
Real-Time Fluid Distribution Determination in Matrix Treatments Using DTS
Authors: Glasbergen Gerard , Gualtieri Dan , Van Domelen Mary , Sierra José
Published: March 2009

In matrix treatments, placement of the injected fluids is essential for success. Over the years, several diversion and placement techniques have been applied to obtain a desired fluid distribution. Real-time evaluation of a treatment was limited to observing injection pressures or bottomhole pressures. These measured pressures provided information on the diversion process. The application of distributed-temperature sensing (DTS) during matrix treatments to monitor the temperature profiles along the wellbore in real time is a recent method to obtain a qualitative indication of the fluid distribution. In this paper, we discuss if DTS can also be used to quantify the fluid distribution during a matrix treatment.

For the real-time quantification of the fluid distribution during a matrix treatment from temperature surveys, both real-time readouts of the temperature surveys and an accurate real-time model are needed. With DTS, the real-time readout is a feasible technique developed to present and evaluate the temperature surveys in real time. Further, a coupled wellbore and near-wellbore thermal model is available that runs in real time. This paper describes these techniques, models, and validations using several case histories.

In addition, an analysis of matrix treatments using DTS temperature surveys, where available, are presented. The models are used in the analysis to obtain calculated fluid flow distribution. We discuss how this methodology can be applied in real time and what benefits quantification of fluid flow distribution offers. Further, we describe what other benefits can be obtained from real-time temperature profiles during stimulation treatments.
A Study Of Normal Slug Flow In An Offshore Production Facility With a Large Diameter Flowline
Authors: Guzmán Vázquez E. , Fairuzov Y. V.
Published: March 2009

Normal (hydrodynamic) slug flow in a pipeline/riser system was studied theoretically and experimentally in this paper. Experimental data were obtained for slug flow in which the length of liquid slugs was larger than the riser height. A transient mechanistic model of this phenomenon was also developed. A good agreement between the model predictions and experimental data was achieved. Simulations of slug flow in an offshore production system with a large-diameter pipeline were performed by use of the developed model. The simulation revealed that long hydrodynamic slugs can accelerate in the riser to a velocity five times greater than the average slug velocity in the pipeline. This fact should be accounted for in the development of operating strategies for such production systems.
Artificial-Intelligence Technology Predicts Relative Permeability of Giant Carbonate Reservoirs
Authors: Al-Fattah Saud M. , Al-Naim Hamad A.
Published: March 2009

Determination of relative permeability data is required for almost all calculations of fluid flow in petroleum reservoirs. Water/oil relative permeability data play important roles in characterizing the simultaneous two-phase flow in porous rocks and in predicting the performance of immiscible displacement processes in oil reservoirs. They are used, among other applications, for determining fluid distributions and residual saturations, predicting future reservoir performance, and estimating ultimate recovery. Undoubtedly, these data are considered probably the most valuable information required in reservoir-simulation studies. Estimates of relative permeability are generally obtained from laboratory experiments with reservoir-core samples. In the absence of the laboratory measurement of relative permeability data, developing empirical correlations for obtaining accurate estimates of relative permeability data showed limited success, and it proved difficult, especially for carbonate reservoir rocks.

Artificial-neural-network (ANN) technology has proved successful and useful in solving complex structured and nonlinear problems. This paper presents a new modeling technology to predict accurately water/oil relative permeability using ANNs. The ANN models of relative permeability were developed using experimental data from waterflood-core-tests samples collected from carbonate reservoirs of giant Saudi Arabian oil fields. Three groups of data sets were used for training, verification, and testing the ANN models. Analysis of results of the testing data set shows excellent agreement with the experimental relative permeability data. In addition, error analyses show that the ANN models developed in this study outperform all published correlations.

The benefits of this work include meeting the increased demand for conducting special core analysis (SCA), optimizing the number of laboratory measurements, integrating into reservoirsimulation and reservoir-management studies, and providing significant cost savings on extensive laboratory work and substantial required time.
Practical Use of New Microbiology Tools in Oil Production
Authors: Skovhus Torben Lund , Højris Bo , Saunders Aaron Marc , Thomsen Trine Rolighed , Agerbæk Mikkel , Larsen Jan
Published: March 2009

Culture-based methods of traditional microbiology applied to the microbiological processes involved in souring of oil fields and microbiologically influenced corrosion (MIC) pose a risk of yielding inadequate and contradictory results. Any cultivation step will almost certainly alter the population characteristics and, thus, alter the results on which any evaluation will be based. The need for cultivation-independent methods has, over the past 10 years, facilitated the development of several analytical methods for the determination of microbial identity, quantity, and, to some extent, function, applied directly to samples of the native population. This development so far has been fairly limited regarding practical application, and it has only recently been transferred to the offshore industry.

In this paper, we demonstrate the features of these novel techniques and the benefits of applying them to two situations often encountered in offshore oil production in the North Sea—nitrate injection and MIC.

The microbiological tools are based on the detection of the genetic material in microorganisms. The methods include direct counting of specific groups of microorganisms with microscopy by use of fluorescent in-situ hybridization (FISH) and other methods that are based on direct extraction of cell genetic material (i.e., DNA/RNA), such as quantitative polymerase chain reaction (qPCR) and denaturing-gradient gel electrophoresis (DGGE). The paper will describe these relatively novel molecular techniques briefly.

The paper documents the microbial-population shifts related to water breakthrough in a nitrate-treated reservoir and shows that key microbial populations can be identified and, thereby, this can lead to the creation of new and strengthened surveillance strategies on microorganisms that cause souring in these systems.

Additionally, we have shown that when applying these novel techniques to aggressive corrosion attacks, especially under deposit corrosion, molecular techniques are powerful tools in identifying the most probable corrosion process in which microorganisms are implicated.

These examples are described and related to offshore operations. Special focus is given to the use of the new and improved microbiological data in relation to designing and testing remedial actions toward oilfield souring and MIC.
Carbon Dioxide Transport and Sorption Behavior in Confined Coal Cores for Carbon Sequestration
Authors: Jikich Sinisha A. , McLendon Robert , Seshadri Kal , Irdi Gino , Smith Duane H.
Published: March 2009

Measurements of sorption isotherms and transport properties of carbon dioxide (CO2) in coal cores are important for designing enhanced coalbed-methane/CO2-sequestration field projects. Sorption isotherms measured in the laboratory can provide the upper limit on the amount of CO2 that might be sorbed in these projects.

Because sequestration sites will most likely be in unmineable coals, many of the coals will be deep and under considerable lithostatic and hydrostatic pressures. These lithostatic pressures may reduce the sorption capacities and/or transport rates significantly. Consequently, we have studied apparent sorption and diffusion in a coal core under confining pressure. A core from the important bituminous coal Pittsburgh #8 was kept under a constant, 3D effective stress; the sample was scanned by X-ray computer tomography (CT) before, then while, it sorbed CO2. Increases in sample density because of sorption were calculated from the CT images. Moreover, density distributions for small volume elements inside the core were calculated and analyzed. Qualitatively, the CT showed that gas sorption advanced at different rates in different regions of the core, and that diffusion and sorption progressed slowly. The amounts of CO2 sorbed were plotted vs. position (at fixed times) and vs. time (for various locations in the sample). The resulting sorption isotherms were compared to isotherms obtained from powdered coal from the same Pittsburgh #8 extended sample.

The results showed that for this single coal at specified times, the apparent sorption isotherms were dependent on position of the volume element in the core and the distance from the CO2 source. Also, the calculated isotherms showed that less CO2 was sorbed than by a powdered (and unconfined) sample of the coal. Changes in density distributions during the experiment were also observed. After desorption, the density distribution of calculated volume elements differed from the initial distribution, suggesting hysteresis and a possible rearrangement of coal structure because of CO2 sorption.
Extended Analysis for Gas Condensate Systems
Authors: Hosein Raffie , McCain William D.
Published: March 2009

Equation of State (EOS) predictions for gas condensate systems require extended analysis beyond the heptanes plus (C7+) fraction. In the absence of experimental data, several schemes have been proposed to extend these compositional data based on the observation that a single straightline relationship exists between log of mole percent and molecular weight for these pseudocomponents or single carbon number (SCN) fractions.

An examination of compositional analysis for gas condensate systems showed a discontinuity in the relationship between mole percent and molecular weight at C8 and C13. As a result, two straight lines are needed for a more accurate description of SCN composition; one from C8 to C12, and the other from C13 and beyond. When applied, this new universal observation gives an improved prediction of SCN composition. An average absolute deviation of less than 6.0% between the predicted and experimental composition was obtained using parameters from two straight lines. From a single straightline relationship, this difference was as high as 36.0%.

This new observation provides the basis for defining the partial experimental analysis required for applying extended models for a more accurate description of SCN composition. For the logarithmic distribution, a partial analysis to C20+ is required to define the change in slope at C13 and beyond. For the three parameter gamma distribution function, a partial analysis is required up to C14 and splitting can be applied from C14+ and beyond. These widely used models are not suitable for extending the C7+ fraction.
Technology for Confecting Polymer Solution With Desalinated Produced Water
Authors: Liu Shumeng , Dong Xigui , Ban Hui , Wang Tao , Pan Wenlong , Yu Haijun , Guo Cuiling , Suo Chunlei
Published: March 2009

Polymer-flooding technology has been used widely in the Daqing oil field of China in recent years. To maintain the viscosity of a polymer solution, fresh water typically is used to confect the polymer solution instead of produced water. In doing so, a problem emerges—the produced water cannot be injected completely into the stratum. The superfluous produced water has to be treated to meet the requirements of discharge, which increases the cost of oil production. In this study, the produced water is desalinated through the implentation of of an electrodialysis principle. A set of experimental equipment that can desalinate produced water at a capacity of 300 m3/d was established at a produced-water-treat-ment station in the Daqing oil field. The experiment's results indicate that the total salinity of desalinated produced water can be less than 1000 mg/L. The polymer solution confected with desalinated produced water has more statistically significant characteristics than fresh water in that the viscosity increases by 63.5% and the recovery rate increases by 4.5%. This experimental study will be beneficial to keeping the balance of oily-water production and injection in oil fields. This technology for pro-duced-water desalination will have better application prospects in the polymer-flooding process.
A Methodology To Reduce Uncertainty Constrained to Observed Data
Authors: Maschio Célio , Schiozer Denis J. , Filho Marcos A. B. Moura , Becerra Gustavo G.
Published: March 2009

This paper presents a new method to deal with uncertainty mitigation by using observed data, integrating the uncertainty analysis and the history-matching processes. The proposed methods are robust and easy to use, and offer an alternative to traditional history-matching methods. The main characteristic of the method is the use of observed data as constraints to reduce the uncertainty of the reservoir parameters. The main objective is the integration of uncertainty analysis with history matching, providing a natural manner to make predictions under reduced uncertainty. Three methods are proposed: (1) probability redistribution, (2) elimination of attribute levels, and (3) redefinition of attribute values. To test the results of the proposed approach, we investigated three reservoir examples. The first one is a synthetic and simple case; the second one is a synthetic but realistic case; and the third one is a real reservoir from the Campos basin of Brazil. The results presented in the paper show that it is possible to conduct an integrated study of uncertainty analysis and history matching. The main contribution of this work is to present a practical way to increase the reliability of prediction through reservoir-simulation models that incorporate uncertainty analysis in the history period and provide reliable reservoir-simulation models for prediction forecast.
Seawater in Chalk: An EOR and Compaction Fluid
Authors: Austad Tor , Strand Skule , Madland Merete V. , Puntervold Tina , Korsnes Reidar I.
Published: March 2009

North Sea chalk reservoirs are characterized as being purely biogenic and naturally fractured, having low matrix permeability and very high porosity (30 to 45%). The reservoir temperature is usually high, more than 90°C, and the wetting conditions appear to be moderately water-wet to neutral. Even though the permeability contrast between the matrix and fractures is significant, the injection of seawater has been a great success with the Ekofisk field as an example (estimated oil recovery is now approaching 50%). Seawater improves the water wetness of chalk, which increases the oil recovery by spontaneous imbibition and viscous displacement.

During the primary production phase by pressure depletion, extensive compaction was observed and, at that time, it was regarded as an important drive mechanism for oil recovery. The compaction continued in the waterflooded areas even though the reservoir was repressurized by the injected seawater. The phenomenon has been described as water weakening of chalk, and production costs have increased because of the loss of wells and substitution of platforms.

This paper gives an overview of the chemical aspects of the interaction between seawater and the chalk. Surface active components in seawater, such as Ca2+, Mg2+, and SO42-, will play an important role in both wettability modification and rock mechanics. In that sense, injection of seawater into chalk must be regarded as a tertiary-oil-recovery technique. Chemical models describing the wettabilty alteration and enhanced water weakening of chalk by seawater are suggested and presented.
Effects of Steam on Heavy Oil Combustion
Authors: Lapene A. , Castanier L. M. , Debenest G. , Quintard M. , Kamp A. M. , Corre B.
Published: March 2009

In-Situ Combustion

In-situ combustion (ISC) is an enhanced oil-recovery method. Enhanced oil recovery is broadly described as a group of techniques used to extract crude oil from the subsurface by the injection of substances not originally present in the reservoir with or without the introduction of extraneous energy (Lake 1996). During ISC, a combustion front is propagated through the reservoir by injected air. The heat generated results in higher temperatures leading to a reduction in oil viscosity and an increase of oil mobility. There are two types of ISC processes, dry and wet combustion.

In the dry-combustion process, a large part of the heat generated is left unused downstream of the combustion front in the burned-out region. During the wet-injection process, water is co-injected with the air to recover some of the heat remaining behind the combustion zone. ISC is a very complex process. From a physical point of view, it is a problem coupling transport in porous media, chemistry, and thermodynamics. It has been studied for several decades, and the technique has been applied in the field since the 1950s. The complexity was not well understood earlier by ISC operators. This resulted in a high rate of project failures in the 1960s, and contributed to the misconception that ISC is a problem-prone process with low probability of success. However, ISC is an attractive oil-recovery process and capable of recovering a high percentage of oil-in-place, if the process is designed correctly and implemented in the right type of reservoir (Sarathi 1999).

This paper investigates the effect of water on the reaction kinetics of a heavy oil by way of ramped temperature oxidation under various conditions.
Application of Artificial Neural Networks to Downhole Fluid Analysis
Authors: Hegeman Peter , Dong Chengli , Varotsis Nikos , Gaganis Vassilis
Published: March 2009

Reservoir characterization and asset management require comprehensive information about formation fluids. Obtaining this information at all stages of the exploration and development cycle is essential for field planning and operation. Traditionally, fluid information has been obtained by capturing samples and then measuring the pressure/volume/temperature (PVT) properties in a laboratory. More recently, downhole fluid analysis (DFA) during formation testing has provided real-time fluid information. However, the extreme conditions of the downhole environment limit the DFA-tool measurements to only a small subset of the fluid properties provided by a laboratory. Nevertheless, these tools are valuable in predicting other PVT properties from the measured data. These predictions can be used in real time to optimize the sampling program, to help evaluate completion decisions, and to understand flow-assurance issues.

The petroleum industry has devoted much effort to developing computational methods to model phase behavior. Two approaches are prevalent—simple correlations and equation-of-state (EOS) models. However, in recent years, artificial-neural-network (ANN) technology has been applied successfully to many petroleum-engineering problems, including the prediction of PVT behavior. ANN technology can recognize patterns in data, adjust dynamically to changes, infer general rules from specific cases, and accept a large number of input variables. An ANN architecture can allow for continuous improvement by expanding the training database with new data.

In this paper, we present the application of ANN technology to DFA. We demonstrate this with an ANN model that uses the DFA-tool measurements of fluid composition as input and produces predictions of gas/oil ratio (GOR), a key PVT property used in real time to monitor a formation-tester sampling job. The ANN also provides an uncertainty estimation of its outputs as a quality-assurance indicator. We compare ANN results with those from the algorithms used by DFA tools.
Improved Fluid Characterization for Miscible Gas Floods
Authors: Egwuenu A. M. , Johns R. T. , Li Y.
Published: March 2009

Equations of state (EOSs) are typically tuned to black-oil pressure/volume/temperature (PVT) data such as constant volume-depletion, constant-composition-expansion, differential-liberation, and separator tests. Other PVT data more appropriate for gas injection could include multicontact and swelling tests and slimtube tests. The standard method of tuning, however, does not typically incorporate important displacement parameters, such as the minimum miscibility pressure (MMP), minimum miscibility enrichment (MME), or the likely compositions that result in a reservoir from condensing-vaporizing (CV) displacements.

This paper demonstrates an improved reservoir-fluid-characterization procedure for miscible gas floods that can represent the interaction of flow and phase behavior more accurately. We demonstrate the approach for two displacements, an 11-component CO2 flood and a 12-component enriched-gas flood. The method-of-characteristic (MOC) theory is used to determine the MME (or MMP) of both lumped and unlumped models. The results show that by tuning to the calculated MME/MMP, fewer pseudocomponents are required to characterize the fluid than with conventional tuning methods. For the cases studied, fluids lumped to as few as four or five pseudocomponents can provide a good match to the composition profiles and oil recoveries of the unlumped models.
Wettability Alteration in Gas-Condensate Reservoirs To Mitigate Well Deliverability Loss by Water Blocking
Authors: Noh Myeong , Firoozabadi Abbas
Published: March 2009

Liquid blocking in some gas-condensate reservoirs is a serious problem when the permeability is low (for example, of the order of 10 md or less). The current practice centers mainly on hydraulic fracturing to improve gas flow. In most cases, the frequency of application results in high costs. An alternative is the permanent alteration of wettability from liquid-wetting to preferentially gaswetting. In this work, we present an experimental study of wettability alteration to preferential gas-wetting using a multifunctional surfactant and polymer synthesized for this particular application. The treatments are performed with an alcohol-based-surfactant/ polymer solution. We treat Berea cores and reservoir-rock samples from two gas-condensate reservoirs. In one of the reservoirs, water blocking has resulted in a significant reduction of well deliverabil-ity. The treatment provides significant improvement on the phase mobility. In this study, our focus is the investigation of water/gas two-phase flow at high temperatures (80 and 140°C).

Basic measurements such as contact angle, spontaneous imbibition, and the effect on the absolute permeability are discussed. The initial liquid saturation at the time of treatment may have an influence on the wettability alteration. The results of the treatment on oil-saturated and water-saturated cores are presented. The treatment by alcohol without using the polymer is compared and discussed. Two-phase-flow tests in single-phase and two-phase injections are performed before and after the treatment using brine and gas. Relative permeabilities of gas and water are measured, and the improvement after the treatment is presented. Various measurements in our work show that water and gas relative permeability increase significantly in a wide range, especially at high liquid saturation.
Environmental Products Manufacturing: A Look inside the Green Industry
Authors: Becker Randy A , Shadbegian Ronald J
Published: March 2009

The green industry is often noted in discussions of the costs and benefits of environmental policy, and it has been characterized as a unique industry with substantial potential for employment growth, well-paying green jobs, and export opportunities. In this paper, we examine the characteristics and recent economic performance of the green industry, using establishment-level data on environmental products manufacturers (EPMs) from the 1995 Survey of Environmental Products and Services, together with data from the Annual Survey of Manufactures and the Census of Manufactures. Results suggest that there are some differences between EPMs and their non-EPM counterparts in the same industry, in terms of employment, employee compensation, exports, and productivity. However, we do not find any evidence that EPMs performed any better than otherwise similar plants, in terms of survival, employment growth, wage growth, and export growth. We suggest that the green industry (as defined here) may not be as exceptional as is sometimes maintained.
Staff Accounting Bulletin No. 108 Disclosures: Descriptive Evidence from the Revelation of Accounting Misstatements
Authors: Keune Marsha B. , Johnstone Karla M.
Published: March 2009

SYNOPSIS: The purpose of this paper is to provide a descriptive analysis of companies’ previously uncorrected financial statement misstatements using disclosures recently mandated by Staff Accounting Bulletin No. 108 (SAB No. 108). We analyze 355 companies that disclose and correct 792 misstatements in their financial statements filed from November 15, 2006, to February 15, 2008. We present descriptive evidence on the size and industry distribution of companies who disclose SAB No. 108 adjustments, showing that larger companies and those in the banking/insurance/real estate industries are most commonly represented in our sample. We also describe the types of audit firms that are associated with these companies. The results show that the concentration of sample companies in the banking/insurance/real estate industries are most often audited by the smallest audit firms in the market, and there is considerable variation in the application of quantitative materiality thresholds for SAB No. 108 disclosures across audit firms. Finally, our descriptive analyses reveal insights about the nature, direction, and magnitude of specific misstatements corrected by SAB No. 108. For example, we show that the most common SAB No. 108 misstatement corrections involve current liabilities, deferred taxes, revenue recognition, and leases. In addition, many companies in our sample used SAB No. 108 to correct misstatements identified in the current year to avoid restating prior period financial statements.
Reconsidering Revenue Recognition
Authors: Schipper Katherine A. , Schrand Catherine M. , Shevlin Terry , Wilks T. Jeffrey
Published: March 2009

SYNOPSIS: This commentary summarizes the materials presented and some of the discussion at the November 2007 AAA/FASB Financial Reporting Issues Conference. The topic of the conference was revenue recognition, and the IASB/FASB were considering two new models: the customer consideration model and the measurement model. This commentary provides some background on revenue recognition, discusses the need for a new model, and presents the two models. The conference discussion highlighted that the two proposed models are based on a single conceptual approach but differ in measurement issues. Key aspects in both models are the identification of contractual performance obligations between the seller and customer (which gives rise to a contract liability) and determining when the performance obligation is satisfied (equivalently, when the contract liability is extinguished) and revenue is recognized.
Nonfinancial Performance Measures as Coordination Devices
Authors: Baiman Stanley , Baldenius Tim
Published: March 2009

ABSTRACT: We investigate how nonfinancial performance measures (NPMs) can be used to encourage cooperation across divisions. The implementation of a project often requires joint efforts by multiple divisions. However, privately informed division managers sometimes find it in their self-interest to forgo profitable joint projects or to underinvest in relationship-specific assets. By treating the implementation of a joint project (e.g., a major process improvement or new product development) as an NPM, we show that paying the division managers discrete bonuses tied to this NPM improves the efficiency of project implementation and upfront investments. We derive how the optimal implementation bonus trades off distortions in ex post implementation and ex ante investments. In a dynamic version of the base model with learning-by-doing, we show that conditional on a project being implemented early on, the implementation bonus in subsequent periods will be higher than if the earlier project had not been implemented.
An Experimental Investigation of the Positive and Negative Effects of Mutual Observation
Authors: Bloomfield Robert , Hales Jeffrey
Published: March 2009

ABSTRACT: We use two experiments to test predictions about the positive and negative impacts of allowing analysts to revise their forecasts in light of the consensus forecasts. We find that such mutual observation not only facilitates information aggregation, but also induces free riding, which offsets the benefits of information aggregation unless incentives for accuracy are high. In our second experiment, we find that participants acting as investors anticipate these effects in the consensus and adjust their own forecasts accordingly. Our study demonstrates that the positive and negative effects of mutual observation are more complex than typically portrayed in the debate about analyst independence, and provides a framework that can be used in future research on the interactive nature of public forecasting.