bluuebunny/crossref_metadata_2025_split huggingface dataset:
Combined Saturation and Production Monitoring Logs for Water Flood Optimization
Authors: Elshahawi H. , Gad K. , Hassan A. 
Published: December 2007

Abstract
Despite the old and extensive use of water flooding as a secondary oil recovery scheme, the actual performance of a given water flood is still often difficult to predict even in the most homogeneous of reservoirs. This performance is heavily dependent on the injection pattern, fluid mobilities, as well as reservoir heterogeneity. For this reason, it is essential that the actual performance of a water flood be measured in order to be able to optimize that performance. This is best accomplished through the combined use of reservoir saturation and production logging tools.
The Reservoir Saturation Tool (RST) provides cased hole reservoir saturation using the water salinity-dependent Sigma capture cross-section measurement as well as a salinity-independent measurement of oil saturation using carbon-oxygen ratio. The latter is especially useful in fresh water and mixed/unknown salinity environments, such as might be expected in a water-injection environment. Production logging, on the other hand, provides information on zonal fluid contributions, fluid typing, as well as clues to fluid movement inside and outside the well bore. The use of shut-in as well as flowing surveys adds a third (time) dimension to the picture.
This paper presents a case of water flood performance monitoring from the Younis Field, operated by the Gulf of Suez Oil Company of Egypt, and illustrates the data analysis cycle involved. The role of the analyst is to piece all the measurements together and come up with a hypothesis to explain what may be happening. This hypothesis is then tested against production data, injection data, and other reservoir data. It is then refined and fine-tuned until a satisfactory explanation is found for all the observed phenomena. The resulting conclusions are highly valuable for the assessment and subsequent optimization of the injection pattern.
Application of Produced Water Technology Practices in Indonesia Upstream Petroleum Industry
Authors: Priatna R. , Wusono S. B. , Bledoeg R. I. 
Published: December 2007

Abstract
Produced water still makes up the largest waste stream in up stream hydrocarbon (E & P) industry in Indonesia. Processing and disposing of produced water can make the difference between making a profit and losing money.
Understanding produced water and its unique nature in Indonesia is essential in designing and operating treatment systems. The regulatory requirement is still growing here, and continuous inputs on best practicable technologies available to the regulatory bodies should be maintained and enhanced.
Throughout the history of Petroleum production, since more than 100 years ago, gravity settling tank is the only best known in industry, but recent improvements in processing technologies are added into the old installations. More sophisticated separating systems have been installed and prove to meet the less stringent regulatory requirements. In offshore operations, especially in environmentally sensitive waters, practice with hydro-cyclone technology has been applied. While in onshore, injection to disposal wells are the safe and environmentally sound technology can be applied.
Monitoring Well Performance using Multiphase Flow Meter
Authors: Retnanto Albertus , Azim Azriz 
Published: December 2007

Abstract
A multiphase flow meter has been developed for determining oil, water, and gas rates simultaneously. This evolution combines accurate and repeatable flow rate measurements without prior well information, to offer shorter well stabilization periods to enable a significantly reduced flow period. Multiphase meter well testing offers significantly more detailed information on the well(s) performance than the standard test separator.
The multiphase meter provides the need for light operation, reduction in human error and a significant increase in safety and assures increased environmental control. Furthermore, the well test set up does not require extensive numbers of pressurize lines and safety devices as per a conventional well test. The fast acquisition device monitors the wells ‘heart-beat’ throughout the well test. The test period could be reduced to a half of a normal production testing as the trends are being displayed in real time. Thus, giving the user the capability to test more wells per day. On top of this the meter is completely environment friendly, as no burning of gas has to be performed during the tests, all the well effluents are returning to the production line as there is no need for separation.
Periodic testing with accurate rate measurement and repeatability is the key for production optimization of a well. A multiphase meter has been used to monitor and optimize the production performance for artificially lifted wells. Using this multiphase meter, changes in the well performance can be observed immediately in real time. This allowed the operations engineer to manage decisions in real time as to what interventions were desired to optimize the outflow. The engineers now have the ability to do analysis of producing formations based on true accurate real time test data. The multiphase meter has improved visibility into well and reservoir performance.
Improvement of Sweep Efficiency by Microbial EOR Process in Fuyu Oilfield, China
Authors: Nagase K. , Zhang S. T. , Asami H. , Yazawa N. , Fujiwara K. , Enomoto H. , Hong C. X. , Liang C. X. 
Published: December 2007

Abstract
This field test for Microbial EOR (MEOR) has been carried out in Fuyu oilfield, China since 1996. Waterflooding by a patterned flood has been applied for over 20 years and various measures to decrease high water cut has been discussed for long time in Fuyu oilfield.
The objectives of this MEOR project are to increase oil production from a waterflooded reservoir and to evaluate ability of microorganisms screened in our study. In this field test a microorganism named CJF-002 was applied to reservoir. CJF-002 has an ability of producing insoluble polymer metabolically on the condition that fed on nutrient. This microbial process has focused on plugging high permeable zones by produced insoluble polymer to reduce water channeling.
Actually, microbial approach using CJF-002 has been performed by injecting into (1) production wells as huff-n-puff test (single cycle) for confirming polymer production potential and (2) injection wells as microbial treatment for water injection profile modification. In huff-n-puff test, CJF-002 and molasses were injected into 6 production wells. Among them, 4 wells indicated oil production increase and water cut decrease. Based on these possible results of huff-n-puff test, microbial treatment was conducted at injection wells for injection profile modification. In the treatment, cell count of CJF-002 and concentration of insoluble polymer in the sample taken at the manifold and some production wells were measured to investigate the metabolic activity of CJF-002 by colony forming unit (CFU) method and HPLC, respectively. Moreover, logging such as RST and WFL and tracer test were conducted before and after microbial treatment to evaluate the effect of microbial treatment. As a result, microbial propagation and metabolic activity was confirmed, however, the effect of injection profile modification has not been confirmed yet. This paper presents results and status of MEOR field test conducted in Fuyu oilfield, China.
Using Genetic Algorithms to Improve Investment Decision Making
Authors: Sarich M. D. 
Published: December 2007

Abstract
Investment decision-makers in the oil and gas industry are faced with an extremely complex process when attempting to decide on the optimum mix of projects to pursue. Almost all firms are faced with constraints such as capital budgets, volume commitments and/or dependent and mutually exclusive projects. Likewise, attempts to include the objectives of planning, finance and engineering can make it almost impossible to find the optimum mix of projects using traditional selection methods.
Indicators from discounted cash flow analysis such as net present value, rate of return and profit investment ratios have traditionally been used to rank projects, however these rankings will not necessarily produce the best result. In addition, unless the number of potential projects under consideration is very small it can be unfeasible to evaluate all of the possible permutations. Therefore, how does one know if the best value-creating portfolio of projects has been chosen?
A recently developed technique for solving this type of problem is the use of Genetic Algorithms. Borrowing from the biological field of evolution, algorithms have been developed that can be applied to find a combination of projects that approach the true optimum, taking in to account numerous business constraints, within an acceptable time frame.
This paper describes the theory behind genetic algorithms and their application to investment decision making in the oil and gas industry. A worked example for a hypothetical company is then used to demonstrate the potential impact of using the technique.
Reservoir Engineer and Artificial Intelligence Techniques for Data Analysis
Authors: Tapias O. , Soto C. P. , Sandoval J. , Pérez H. H. , Bejarano A. 
Published: December 2007

Abstract
Different knowledge areas on the petroleum industry require to solve problems related with data transformation processes needed to generate information and knowledge. This paper describes data analysis steps using Artificial Intelligent techniques which include the problem exploration, space analysis, surveying data source, data preparation and building the appropriate data mining model. Predictive and inferential models are illustrated by applications implemented using Unsupervised Artificial Neural Networks and a Fuzzy Rule Diagnosis System. (1) The first application is able to identify well zones potentially producing hydrocarbons in Colombian PETROLEA field. This reservoir is mainly a fractured and calcareous formation. The knowledge predictive model uses Fuzzy Learning Vector Quantization (FLVQ) built from historical production tests data and spontaneous potential, short and long resistivity well logs used for training, testing and validating the model. The final Bravais & Pearson correlation factor obtained is 0.95. (2) Finally a Fuzzy Rule Diagnosis System is applied to enhanced oil recovery screening comparing technical information from reservoir, well and oil properties. The model uses heuristic and lab results for knowledge base implementation adapted to Colombian oil fields.
Experiences with Gravel Packing in the South Tapti Gas Field - An Unconsolidated, High Permeability Sandstone Reservoir
Authors: Das Subhas C. , Garred Michael A. , Suhail Kak 
Published: December 2007

Abstract
The South Tapti gas field, located in the Arabian Sea off the western coast of India, has been on production for the last three years. Drill Stem Tests (DST) conducted in five zones in the first appraisal well showed high sand production in all the tests at drawdowns as low as 20 psi. Due to the unconsolidated nature of the reservoir sand, it was decided to gravel pack all future wells.
Initially, the High Rate Water Pack (HRWP) technique was used on 13 completions including some stack and selective completions. Due to a change in the drilling fluid to an oil based mud (OBM) system and the higher damage associated with the it, it was later decided to switch the gravel packing technique to ‘Frac and Pack’. This involved creation of a small frac to bypass the near wellbore damage using a gel-based fluid, followed by gravel placement using the HRWP. The Frac & Pack technique was tried on 10 completions.
Extensive production and pressure data collected on the above completions show that the ‘Frac & Pack’ technique has led to a decrease in the mechanical skin by almost 70 %. More importantly, it has also been responsible for decreasing the Rate Dependent Skin Coefficient, D, by 50 %, which has a greater impact on the well productivity since these wells are produced at average rates of 25 MMSCFD.
This paper describes the gravel packing techniques used in the South Tapti gas field, their evolution and the results achieved.
Thermal Stress of Carbonate Rocks: An Experimental Approach
Authors: Zekri Abdulrazag Y. , Chaalal Omar 
Published: December 2007

Abstract
The most commonly used methods of describing fluid flow in oil reservoirs use constant rock properties. However, these methods are not applicable to reservoirs that undergo changes in the rock properties due to variation in pore pressure. A common characteristic of fractured reservoirs is sensitivity of permeability and porosity to effective stress. The in-situ stress, in itself, can be of mechanical or thermal origin. The thermal stress can be significant in thermal enhanced oil recovery schemes, injection of cold fluid in hot formation during water flooding or wastewater disposal, or during hydraulic fracturing.
An extensive literature review reveals that the research in this area has focused only on thermal recovery of heavy oil. Little has been done to investigate the onset and propagation of fractures under thermal stress or even mechanical stress. Consequently, this paper is devoted to investigate fracture development and propagation in carbonate formation under thermal and mechanical stress. A series of experiments were ingeniously designed to study the effect of thermal stress on fractured carbonate formation. Laboratory experiments were conducted to determine stress-strain relationship and their time dependence, fracturing and propagation of fractures. A computer image analyzer was used to observe the fracture/fissures distribution for various cases of thermal stress on carbonate rocks. The role of thermal and mechanical stress in determining orientation and propagation of fractures was also studied.
Process for Recovery of Extremely Shallow Heavy Oil
Authors: Osterloh W. Terry , Jones Jeff 
Published: December 2007

Abstract
In this paper, we propose a new process for recovery of heavy oil from sands at depths of 100 ft or less and report its feasibility as determined by reservoir simulation. The process, called blanket heating, recovers oil by the traditional mechanisms of viscosity reduction and gravity drainage, but avoids the problem of handling large volumes of injected fluids and reduces the risk of surface emissions that would occur with typical steam EOR methods.
Simulation results indicate that excellent, thermally efficient oil recovery is possible. Process sensitivity to many critical parameters was determined.
Application of Flexible Gridding Technique to Simulate Gravity Drainage in ESOZ
Authors: Ahmed Mahbub , Singh S. P. 
Published: December 2007

Abstract
Eastern Shallow Oil Zone (ESOZ) of the Elk Hills field is a thick sandstone reservoir whose structure is complicated by the presence of numerous faults. ESOZ is being exploited by both vertical and horizontal wells. This paper describes the adaptive flexible simulation grid employed and the results obtained in modeling the South Flank of Eastern SOZ. Representing a highly faulted reservoir through ordinary Cartesian grids poses challenges to the reservoir simulation engineers in that the fluid flow across these geological boundaries are not modeled properly. Also, horizontal and inclined wellbores present near wellbore phenomena that are difficult to be represented by classical Cartesian Grid system. The use of Perpendicular Bisection (PEBI) grid in the study has greatly enhanced the quality of reservoir simulation. The recovery from south flank having a dip of about 25 degrees is dominated by gravity drainage. The reservoir pressure is depleted to 100 – 200 psi in the oil productive zone. The objective of the model study was to understand the degree of sealing across the faults, sand units and estimate future recovery under various reservoir management options. Eighty years of production history was simulated to properly establish current pressure and saturations in the model. Next, several forty-year prediction runs were performed to investigate the effect of gas injection, gravity drainage, infill drilling and water injection. The model results show that a combination of gas injection and infill drilling would further increase future oil recovery from the south flank.
Predicting Foamy Oil Recovery
Authors: Mastmann Manuel , Moustakis Michael L. , Bennion D. Brant 
Published: December 2007

Abstract
With a current recovery of only 5 percent, Albania's largest oilfield Patos-Marinza, first commercially produced in 1939, still yields a potential of more than 100 MMbbl reserves of 10 – 12°API oil from a depth of 1600 m. A consortium consisting of the Albanian Albpetrol, the German Preussag Energie, the British Premier Oil, and the IFC, the private sector arm of the World Bank, are making plans to improve oil recovery.
Testing wells producing 1-2 m3/d yielded rate improvements with Progressive Cavity Pumps up to 30 m3/d with sandcuts around 10 to 35 %. PVT analysis of the oil with a relatively high solution-GOR of 35 m3/m3 shows a strong tendency to foam (gas in microbubbles without forming a continuous gas phase) below the bubble point, near the initial reservoir pressure. Core tests with different depletion rates resulted in primary oil recoveries of greater than 30 %.
For predicting project recovery and eonomics a black oil simulation model was built with ECLIPSE on the basis of the lab results. The sand production was inferred through channels laid out in a star-like manner with a single cross connection. Constructing type wells a sensible forecast including sand was attained.
The paper discusses all measurements and results in the context of present theories of foamy oil and Cold Heavy Oil Production (CHOP).
A Semi-Analytical Pressure Transient Model for Wells in Heterogeneous Linear Reservoirs
Authors: Sagawa Atsushi , Corbett Patrick W. M. , Davies David R. 
Published: December 2007

Abstract
A new semi-analytical model for vertical or horizontal wells in heterogeneous elongated linear reservoirs is presented. In fluvial environments, such reservoirs can be formed due to the effect of low sinuosity river channels.
Transient pressure response or fractional flow rate from well segments can be calculated using the model. To obtain the solution, semi-permeable wall model and strip-wellbore model are used. A wellbore may penetrate several different permeability zones and skin factor can be different along the wellbore. It is shown that early-time linear flow behavior, which can be often seen in acidized carbonate reservoirs, can be approximated by the strip-wellbore model.
Type-curves for the heterogeneous elongated linear reservoirs, which may be used directly in well test analysis, can be generated using the model developed in this study. If the results of production logging are available, they are useful for the analysis since the transition of fractional flow rate from each well segment can be calculated. Such analyses become important to determine the size and rock properties of each heterogeneous zone, which is critical for future production forecast.
The validity of the model is confirmed by comparison with the results of numerical simulation. This study provides a new tool for studying and analyzing the pressure behavior of wells completed in fluvial environments as well as acidized carbonate reservoirs.
Development and Testing of Two-Phase Relative Permeability Predictors Using Artificial Neural Networks
Authors: Silpngarmlers N. , Guler B. , Ertekin T. , Grader A. S. 
Published: December 2007

Abstract
Artificial neural networks (ANNs) provide a powerful toolbox to perform nonlinear, multi-dimensional interpolations. In this paper, we include a new methodology to identify some of the vague nonlinear relationships that exist between rock and fluid properties and relative permeability characteristics. More specifically, we report liquid/liquid and liquid/gas two-phase relative permeability predictors that we have developed using back-propagation networks. In this class of ANNs, information is passed from input layer to output layer, and calculated errors are propagated back to adjust the connection weights in a sequential manner to improve the predictive capabilities of the models. In the development stage, some of the relative permeability data from literature are used during the training stage while some other sets are preserved to test the prediction capabilities of the models. Various rock and fluid properties such as end-point saturations, porosity, permeability, viscosity and interfacial tension and some functional links (mathematical groups coupling various rock and fluid properties) constitute the input parameters of the models. These rock and fluid parameters together with the functional links highlight the dependency of relative permeability characteristics on such properties and functional groups. The models developed for oil/water and oil/gas systems are different in terms of their respective topologies, functional links, and the weight updating schemes. The models are found to successfully predict the field and experimental relative permeability data.
Permeability Calculations from Clustering Electrofacies Technique for the Petrophysical Evaluation in La Peña and Tundy Oil Fields
Authors: Antelo Roberto , Aguirre Omar 
Published: December 2007

Abstract
A relatively new technique has been applied for the purpose of providing more accurate Permeability information and identify rocks types with good fluid flow characteristics from wireline logs data.
The study for which this technique was applied included wells drilled over the last 30 years up to present. When you have a wide range of logging tools and differences in logs scales or presentations it becomes really difficult to identify the existing facies on a depositional cycle just by following the shape of the log curves. Even when you count with a consistent or homogeneous log set of curves, the task of identifying the different facies is often difficult.
The technique used applies the clustering K-Means2 algorithm based on wireline logs characteristics to identify the different Electrofacies. The Electrofacies found were very useful to determine rock types with identifiable fluid flow characteristics. Porosity/Permeabilty relationships were then assigned to the various Electrofacies and used to calculate permeabilties during the log analysis.
The method was applied for 79 wells from La Peña Field and for the 9 wells from the Tundy field and proved to be very successful in dealing with a wide heterogeneous range of wireline log types when working on a multiwell field petrophysical analysis. The application of this technique is very simple if we look at the existing pattern recognition software designed to identify facies that include the complicated stochastic algorithms which usually requires the operation of skilled users in order to obtain impressive results.
This paper presents a description of the clustering K-Means2 algorithm used for the Electrofacies calculations and also shows the permeabilities results obtained in the petrophysical analysis for each of the Facies. Finally some examples of the petrophysical evaluation and the calculated Electrofacies will also be visualized graphically and discussed here.