bluuebunny/crossref_metadata_2025_split huggingface dataset:
Microscopic Visualization with High Resolution Optical-Fiber Scope at Steam Chamber Interface on Initial Stage of SAGD Process
Authors: Sasaki Kyuro , Satoshi Akibayashi , Yazawa Nintoku , Kaneko Fuminori 
Published: December 2007

Abstract
Experiments and numerical simulations on initial stages of the steam-assisted gravity drainage (SAGD) process were carried out. Experimental studies used two-dimensional scaled reservoir models to investigate fluids flow characteristics in the steam chamber and production fluids. The rise and growth of the initial steam chamber were observed and visualization of micro-phenomena at inclined interface on the side of the steam chamber with a high-resolution optical-fiber scope was carried out. Very fine water droplets of 0.01 mm order in size were observed at the interface between steam and heavy oil phases. These droplets entered into heavy oil phase and created emulsion together with the heated oil, which flowed down and was produced from the production well. It was successfully demonstrated that these micro phenomena has an influence on chamber expansion rate in horizontal direction and oil production rate.
The numerical simulation of the SAGD process was also performed. The thermal simulator, CMG's STARS™ was used to simulate the experimental steam chamber growth at the initial stage. The simulation used the two-components (water and heavy oil) black oil, three-phase (water, heavy oil and steam) and three-dimensional numerical model for the physical model. The results from the history-matched numerical simulation were found to be in good agreement with those of the experiments for oil production and steam chamber shape by using the Intermediate3-Stone1 wettability model represents fluids behavior cumulating the microscopic phenomena at the chamber interface. Furthermore, a new process named Surfactant-SAGD injecting a surfactant before starting steam injection to enhance the communication between two wells and mobility of the production fluids was tested.
Production Type Curves for the Hunton Formation
Authors: Frederick Jeff L. , Kelkar Mohan , Keefer Brian 
Published: December 2007

Summary
The Hunton Formation is one of the most promising formations producing oil and gas in Oklahoma. The formation has an anomalous producing behavior. At the inception, the wells produce at relatively high water-oil and gas-oil ratios. Eventually, both the WOR and GOR decrease. This results in increase in oil cut and hence reduction in lifting costs over time. Because of relatively high WOR's, many operators are discouraged from completing the wells, and hence abandoning the effort to produce oil from these formations.
We concentrate on West Carney Field, Lincoln County, Oklahoma for this investigation. The field was "re-discovered" in 1995, and significant drilling activities continue in the field today. The field produces various amounts of gas, oil and water from each well. Because of varying gas oil ratios and water oil ratios over the field, a simple decline curve analysis is not applicable to determine the hydrocarbons in place. Attempts to calculate the reserves based on the electric log data have produced inconsistent results because of poor correlation between log signatures and productivity and connectivity of wells.
In this study, we provide a technique for evaluating the performance of producing wells. Because the wells have variable rates and variable bottom hole pressures, we used the concept of equivalent time as proposed by Agarwal et al. (SPE 57916), and show that we can correctly predict the reserves estimate. Also, we show that it is possible, using Agarwal et al's equivalent time concept, to use automatic type curve matching to predict values of permeability and skin factor.
We evaluate the gas, oil and water rates separately to calculate permeability and skin factor. We then use the results to estimate recovery factors and the quality of our initial completions. This type of analysis is useful for economic evaluation, planning of surface facilities, and future field development and exploitation. Further, if sufficient early production data are available, the procedure can also allow us to predict various reservoir parameters that can be used for additional evaluation.
Evaluation of Crossflow Effects in Multilateral Wells
Authors: Zhu D. , Hill A. D. , Landrum W. R. 
Published: December 2007

Abstract
As drilling and completion technology has advanced dramatically, developing new oil fields faces new opportunities of well structure selection, especially for the fields that are sensitive to issues such as environmental conservation, cost effectiveness, safety control, and well management. Horizontal, multi-branching and multilateral technologies have been used in many field applications all over the world to enhance the reservoir recovery in a cost-effective way. When the well structures become complex, producing from these "fancy wells" could become difficult, and sometimes, detrimental to overall recovery. To study the strategies for optimizing multilateral wells, we have developed a mathematical model to predict well performance for horizontal and multilateral wells using coupled multiphase models of wellbore/reservoir flow. The flow distribution along the laterals is predicted as a function of tubing head pressure (deliverability of the well), and overall well performance as a function of time is predicted by a simple material balance relationship.
A common problem for such wells is that commingled production from multilateral branches can often lead to crossflow from one reservoir compartment to another. The likelihood of crossflow depends on initial reservoir conditions, but also very much on the operating conditions of the well. Deleterious interactions between commingled reservoirs accessed by multilateral wells must be reliably preventable for these types of completions to have broad application. Some case studies and hypothetical examples are presented in the paper to show the procedures for optimizing the well structure and well performance. Production strategies that would help to eliminate crossflow are discussed.
Propagation of Cross-linkers Used in In-Situ Gelled Acids in Carbonate Reservoirs
Authors: Nasr-El-Din H. A. , Taylor K. C. , Al-Hajji H. H. 
Published: December 2007

Abstract
In-situ gelled acids are used in well stimulation to improve sweep efficiency during acid placement. These acids comprise a polymer, a cross-linker and a breaker in addition to chemicals used with regular acids. The gelation reaction in these systems occurs over a narrow range of pH (2-4). The gel forms once the acid reacts with the carbonate formation and the pH rises to a value above 2. The gel breaks once the pH rises above a value greater than 4. Propagation of the crosslinker plays a key role in the success of these acids. However, in a recent paper by Lynn and Nasr-El-Din,1 there was evidence of precipitation of the cross-linker in some systems. The cross-linker is typically a multi-valent cation (iron(III) or zirconium(IV)), which may precipitate at high pH values or react with hydrogen sulfide (in the case of sour wells) to precipitate damaging material. Coreflood experiments were conducted at 100°F in a linear mode to determine the rate of propagation of various cross-linkers in reservoir cores (mainly calcite). This temperature represents bottom hole temperature of seawater injectors in a carbonate reservoir in Saudi Arabia.
Propagation of the cross-linker in carbonate cores was examined by measuring the concentration of the cross-linker in the core effluent and comparing it with the chloride ion concentration (used as a tracer). The profile of the tracer was used to determine dispersion of the acid in the core, whereas the area between the tracer and cross-linker profiles was used to determine the amount of cross-linker precipitated or retained in the core. The effects of acid concentration, slug volume, injection rate, cross-linker type, and polymer loading on the rate of propagation of the cross-linker were examined in detail.
The following conclusions were made. 1. Viscous fingering effects that occur during pumping low-viscosity post-flush fluids affect the propagation of the cross-linker in reservoir cores. 2. The rate of propagation of the cross-linkers depends on the type of cross-linker used (iron, zirconium, etc.), and 3. Results of this study will help production engineers to design acid treatments with minimum damage due to precipitation/retention of the cross-linker.
DOWS Downhole Oil-Water Separation Cross-Waterflood Economics
Authors: Jokhio S. A. , Berry M. R. , Bangash Y. K. 
Published: December 2007

Abstract
Downhole oil-water separation (DOWS) provides the ability to conduct a cross-waterflood using a single wellbore that penetrates stacked waterflood zones. In this application of DOWS technology, production from one waterflooded zone is used as the inlet stream to the separation process. The oil-rich stream is produced to the surface while the water stream is injected into the second zone as shown in Fig. 5.
Potential benefits include reduced well count, reduced lifting costs, reduced expenditures for surface water handling facilities, reduced treating costs, smaller surface footprint and reduced environmental risk. Potential disadvantages include DOWS installation costs, more expensive workovers, more difficult and costly monitoring and larger wellbore requirements.
DOWS technology is widely viewed as a potentially highly valuable technology with a high price tag and a high risk of failure. A major failure node for DOWS installation is the injection zone. Injection into a water flooded zone reduces the injectivity problems, and provides a benefit from the work required to inject the water stream. If a DOWS installation can economically be justified on its own merits anywhere, it will be in a cross-water flood application. The question remains; Can a DOWS cross-water flood be economically justified?
This paper is divided in four parts. First, DOWS technology in general and cross-waterflood application in particular are briefly described. Second, the operational advantages and disadvantages of this application of DOWS technology are briefly discussed. Thirdly the parameters of economic model are reviewed in some detail. Lastly, the characteristics of a waterflood operation that can benefit economically from this technology are summarized.
Energy Sources and Energy Intensity for the Twenty-First Century
Authors: Economides M. J. , Demarchos A. S. , Saputelli L. 
Published: December 2007

Abstract
A country's wealth is closely related to its energy consumption. For example, the United States, the richest nation, with a per capita income of about $34,000 is also one of the highest consumers of energy with an annual per capita consumption of about 355 million British thermal units (MMBTU). Energy consumption is the most discernible national characteristic that separates rich from poor countries. The correlation between per capita energy consumption and per capita income among all nations is clear. However, the energy use in other developed countries is also a function of their geography, the makeup of those countries and even the cultural preferences of their citizens.
Throughout the last two centuries, energy consumption in the creation of wealth and the form of primary energy sources, have not been constant. The process has been dynamic and technology has played a considerable role in the changing of the status of many countries, most notably Japan. Efficiencies developed elsewhere are adopted by other countries and lead to an increase in wealth. Globalization of the economy will certainly aid this process in the future.
Energy consumption and heightened demand worldwide, may prove perhaps the most formidable international challenge of the twenty first century. As early as 2010, at current energy growth, chronic energy shortages are likely to emerge which may evolve into a serious energy crunch. The most logical way to prevent this situation is to transition rapidly to natural gas and, eventually, to hydrogen. In this paper, natural gas is viewed as the compelling next fuel of choice and as the necessary stepping-stone towards hydrogen. Also offered here are production, consumption and transition forecasts.
Applicability of Sachdeva's Choke Flow Model in Southwest Louisiana Gas Condensate Wells
Authors: Guo Boyun , Al-Bemani Ali Soud , Ghalambor Ali 
Published: December 2007

Abstract
Sachdeva's multiphase choke flow model has capabilities of predicting critical-subcritical boundary and liquid and gas flow rates for given upstream and downstream pressures. Although this model was shown to be accurate by Sachdeva et al. in their original paper using laboratory and field data, inaccuracy of the model has been found in other field applications. It is highly desirable for production engineers to find the applicability of this model when it is applied to gas condensate wells.
In this study, the accuracy of the Sachdeva's choke model was evaluated using data from oil and gas condensate wells in Southwest Louisiana. Comparisons of the results from the model and field measurements indicate that Sachdeva's choke model generally under-estimates gas and condensate flow rates. Based on measurements from 239 gas condensate wells it was found that the model under-estimates gas rate and liquid rate by as much as 40% and 60%, respectively. The model also failed to calculate mass flow rates for 48 condensate wells where relatively low-pressure differentials at chokes and high-flow rates were observed.
The investigation further went on to improve the performance of Sachdeva's choke model. It was found that the error of the model could be minimized using different values of choke discharge coefficient (CD). For gas condensate wells, the error in gas flow rate calculations can be minimized using CD = 1.073. However, the error in liquid flow rate calculations for condensate wells is minimum when CD = 1.532.
Reducing Gas Production Decline through Dewatering: A Case History from the Naturally Fractured Aguarague Field, Salta, Argentina
Authors: Aguilera R. , Conti J. J. , Lagrenade E. 
Published: December 2007

Abstract
The Aguarague field is located in the Devonian Basin, NW of the Province of Salta, Argentina. Gas production is obtained from clastics of the Huamampampa formation through an intense network of natural macro and microfractures. The reservoir is in a North-South trending symmetrical anticline.
Five high-deliverability gas wells watered-out between 1991 and 1994 and as a result the field gas production decreased substantially. This triggered a study in 1995 to try to find a means of enlarging the life of the reservoir. The study indicated that without any modifications gas production could be expected to lapse at most to 1999.
This paper describes how a detailed fracture characterization led to a dewatering project using gas lift, which significantly reduced the gas decline of the reservoir. The project also brought back to gas production some of the wells that had previously watered-out. The 1995 forecast is compared with the actual production performance to date.
Stepwise Compositional Simulation of a Multilayer, Giant Gas Condensate Field
Authors: Jimenez T. , Marruffo I. , Cabrera J. , Cosentino L. , Caussade S. 
Published: December 2007

Abstract
The Oficina Formation, Eastern Venezuela, contains large amounts of gas reserves, which are strategic for the energetic policy of the country. In the Zapatos-Mata R field, these reserves are stored in a thick transgressive sequence of deltaic channels and shore bars (over 3000 ft), as rich gas condensate accumulations of various importance, from few to hundreds of Bcf. Over 400 wells have been drilled in the area since the 1950's, which in general have been selectively completed in progressively shallower intervals. Gas injection has been implemented in most of the main reservoirs since the early 1960's.
An integrated reservoir study was started during year 2000, with the aim of establishing a new exploitation strategy by means of a simulation model. However, early in the project, it became obvious that a straight full field simulation would have been a prohibitive task, given the complexity of the geology, the variation in the fluid type and properties, and the number of wells, completed intervals and reservoirs (almost 700 official reservoirs were reported in the study area). Still, the availability of a full field model was deemed critical to establish a representative exploitation plan in the prediction phase, especially because a commingled production option is being considered.
An original procedure was therefore defined, based on a stepwise approach. In a preliminary stage, simulation studies were carried out individually for the most important reservoirs. The modeling was performed using a full compositional formulation. Several of these models were built and partially history matched.
In a later stage, these individual models were lumped together in a progressive mode, while checking the quality of the history match. This process eventually led to the building of a full field model, including all the most important reservoirs and over 80% of the total reserves of the area. This model has about 65 layers and more than 300,000 active cells.
Conclusions of the study showed that this stepwise approach is an interesting option for the full scale simulation of giant multilayer gas condensate reservoirs, since it allows for the decoupling of the problems related to the model building and history match issues, which are faced and solved early in the simulation process. Moreover, individual models can be used for investigating the behavior of the single reservoirs, as well as for special tasks like well performance analysis and sensitivities studies.
Gas Well Decline Analysis Under Constant-Pressure Conditions, Wellbore Storage, Damage, and Non-Darcy Flow Effects
Authors: Nashawi Ibrahim Sami , Qasem Fuad H. , Gharbi Ridha , Mir Mohammad I. 
Published: December 2007

Abstract
This paper presents a simple and accurate method to determine all the reservoir parameters for transient constant-pressure drawdown data of gas wells influenced by wellbore storage, formation damage, and high-velocity flow effects. The working equations are written in such a way that allows a graphical analysis of the measured variable rate with time that is very much similar to the analysis of constant-rate production case. No iterative procedure, multi-rate test, nor non-linear regression is necessitated to determine the formation damage and the non-Darcy flow effects. The well test data analysis requires two plots to directly obtain all the parameters of interest. The formation permeability and the non-Darcy flow coefficient are obtained from the first plot, whereas the skin factor is obtained from the second analysis plot.
This work systematically illustrates the applicability of the derived equations using several simulated examples. The final working equations are written in various forms, which allows the well test analyst to select the form that is most convenient for his application. The advantages of the proposed method are clearly shown when the analysis procedure and results are compared to other analysis techniques.
Innovative Critical Sour Gas Extended Production Test Through Surface Coiled Tubing
Authors: Campbell S. F. , Pettigrew S. M. , Gordey K. N. 
Published: December 2007

Abstract
This paper will describe the deliverability test of a critical sour natural gas well using Coiled Tubing as a surface pipeline. Conventional production deliverability tests are constrained by regulatory limitations on emissions and flaring, affecting test duration and reservoir evaluation. Conventional tests also carry a significant environmental impact and the lost revenue from flared gas hamper the economic justification of the test. This paper will describe the concept, background analysis and the field trial production test performed. A safety-focused procedure was developed using surface Coiled Tubing for in-line testing of high rate critical sour gas wells. This prototyped method allows for a proper evaluation of a well without the commitment and installation of a permanent pipeline, without the volume restraint imposed by regulatory limitations, with no harm to the environment and without compromising economic value. It is projected that this method for well production deliverability tests will become an attractive alternative for the Alberta oil and gas industry.
Well Performance Prediction of a Well Experiencing Changes in Completion
Authors: Marhaendrajana T. , Desroches J. 
Published: December 2007

Abstract
This paper presents a new semi-analytical method to predict the production performance of a well stimulated by acid or hydraulic fracture treatment. The new method considers the production history before stimulation, in contrast to current analytical methods that ignore the production history of the "old" well. The initial condition of the "new" well is based upon an "assumed stabilized condition" of the old well.
The superposition technique has been extensively used in the literature to model production history (i.e., variable flow rate and variable bottomhole pressure history) and predict well performance. There has not been a detailed study using analytical or semi-analytical solutions that includes the change in well completion (well model change) and that investigates the influence of the production history of the unstimulated well on the well performance prediction of the "stimulated" well. This paper addresses both issues.
The semi-analytical method presented here considers changes in well completion, which are becoming more frequent as recompletions become more common. We present validations of this approach using a numerical reservoir simulator for oil and gas reservoirs in which the wells are recompleted with a hydraulic fracture treatment after some initial production.
Hydrate Inhibition in Gas Wells Treated with Two Low Dosage Hydrate Inhibitors
Authors: Lovell Dean , Pakulski Marek 
Published: December 2007

Abstract
Two low dosage gas hydrate inhibitors, antiagglomerant type and a combination antiagglomerant/kinetic polymeric inhibitor have been successfully field tested in a gas producing well. The well located in Canadian foothills posed challenges for the operators. High pressure, low bottomhole temperature and Joule-Thomson gas decompression cooling effect created favorable conditions for gas hydrates at depths below 300 meters. The well would plug-up with hydrates daily in spite of being treated with 400-500 L of methanol. The operator experienced significant monetary losses due to lost production and had to use considerable amounts of chemicals and time to clean-up hydrates from plugged tubings.
The inhibitors were applied downhole in 20% to 10% methanol solution. This novel approach allowed utilization of existing solvent storage and pumping equipment so that no capital spending was required when converting the hydrate prevention program from methanol to LDHI treatment.
The combination inhibitor was diluted to 20% in methanol in a stock tank and pumped into the well at the approximate rate 30 L/day. Similarly, the antiagglomerant was initially used at 20% solution in methanol and later its concentration was lowered to 10%. The daily inhibitor treatment rate was established at 45 L.
Laboratory results indicate the combination product is a better hydrate inhibitor than the antiagglomerant. However, the cost analysis favors the usage of less expensive antiagglomerant in this application.
Following the successful treatment of one well, several more similar gas wells throughout the field were identified and converted from methanol hydrate prevention method to antiagglomerant treatment.