bluuebunny/crossref_metadata_2025_split huggingface dataset:
Data Mining Identifies Production Drivers in a Complex High-Temperature Gas Reservoir
Authors: Shelley Bob , Harris Phillip C. 
Published: March 2009

Summary
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

Summary
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

Summary
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

Summary
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

Summary
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

Summary
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

SummaryThis 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

Summary
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

SummaryNormal (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

SummaryDetermination 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

Summary
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

Summary
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

Summary
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.