bluuebunny/crossref_metadata_2025_split huggingface dataset:
Sand Consolidation Using High-Temperature Alkaline Solution – Analysis of Reaction Parameters
Authors: Moreno F. E. , Mamora D. D. 
Published: December 2007

Abstract
As reported in SPE 62943, Wilmington Tar sand samples were successfully consolidated in the laboratory using high-temperature (250-260°C) solution of sodium carbonate (pH 11-12). The sample was placed in a vertical 18 in. long aluminum cylindrical cell with an ID of 1.5 in. The top half of the cell was thermally insulated while the bottom half was cooled. Hot alkaline solution was injected at 20 ml/min for 3-4 hours at the top of the cell and liquid produced at the bottom of the cell. After each experiment, the cell contents were removed and analyzed to determine if sand consolidation occurred. Thin sections of the sample were analyzed using an electron microprobe to determine any change in shape, size, and composition of the sand pack.
To better understand the process, experiments were subsequently conducted using samples of (a) pure quartz, (b) pure feldspar, and (c) a 50:50 (by weight) mixture of quartz and feldspar. In each case, the grain size was 20-40 mesh. For these cases, zeolites and amorphous silica were deposited on grain surfaces but were insufficient to cause overall sand consolidation. However, when a finer, poorly sorted (50-250 mesh) 50:50 mixture of feldspar and quartz was used, sand consolidation was obtained in 2.5 hours. At the top, hotter part of the cell, equant and acicular zeolite crystals (sodium aluminum silicates) weakly bound the sand grains. At the bottom and cooler part of the cell, the sand grains were strongly bound by amorphous silica. Results to-date indicate that both zeolite and silica may be cementing agents, the grain-bonding strength depending on the grain surface area. Further, the temperature, injection rate, and pH of the alkaline solution, and "curing time" are important process parameters that will be further investigated.
Demulsification Treatment and Removal of In-Situ Emulsion in Heavy-Oil Reservoirs
Authors: Castro Leo U. 
Published: December 2007

Abstract
Cyclic steam injection has been proven to be an effective method for producing heavy oil from low gravity, shallow reservoirs in the San Joaquin Basin of California. The practice of cyclic steaming, however; can cause formation damage in the reservoir that can severely affect the performance of post cyclic steam production.
Cyclic steam operations introduce a high level of energy into a reservoir, a primary element needed for the formation of stable emulsions in highly porous sands. Other necessary elements such as immiscible fluids, formation fines, and oil-wet surfaces are naturally present in most steamdrive reservoirs. Significant fluid velocities and shear forces during steam cycles combine these elements in the wellbore much like the action of a Waring blender in the laboratory. This leads to the creation of stable in-situ emulsions which can partially, or wholly block the production paths into the wellbore.
The use of a surface active, water-soluble blend of oxyalkylated alkanolamines and sulfonates, has shown dramatic improvement over non-chemically enhanced steam cycles. These treatments, applied during different stages of a steam cycle, have resulted in significant and prolonged increases in incremental production. This paper details the successes associated with these types of treatments, and discusses placement technique, candidate profiling, and chemical selection.
Modern Total Well Management - Sucker Rod Lift Case Study
Authors: McCoy J. N. , Podio A. L. , Drake Bill , Rowlan Lynn 
Published: December 2007

Abstract
Oilfield operators continually need to verify that their wells are being produced at the optimum capacity and in a cost effective manner. An integrated analysis of the pumping system is required to reduce operating costs, increase oil production and increase net income. The integrated analysis of the pumping system must include the performance and interaction of all the elements: the prime mover, surface equipment, well bore equipment, down hole pump, down hole gas separator and the reservoir. This integrated analysis methodology is called Total Well Management, TWM. The TWM analysis is made based on data obtained at the surface without entering the well bore and yields an accurate representation of the conditions existing on the surface, within the well bore and within the reservoir. A field case study of a sucker rod lifted well illustrates the procedure and benefits of the Total Well Management methodology.
Fullfield Numerical Simulation Using Geostatistical Reservoir Model of Upper Main Body "B" Reservoir, Monterey Formation, Elk Hills Field, California
Authors: Hampton Thomas J. , Danielli Corinne , McChesney Don , Singh S. P. 
Published: December 2007

Abstract
This reservoir is located in the southern San Joaquin Valley of central California, about 20 miles west of Bakersfield. The Upper Main Body "B" (UMBB) is part of the Upper Miocene Monterey Formation. This turbidite reservoir was initially under crestal gas injection from 1976 to 1988. The reservoir has been under peripheral waterflood since 1983. An integrated study including reservoir characterization and full field simulation was started in late 1998 to evaluate near term enhancements to production.
Geological mapping and correlation generated nine zones based on logs from 725 wells, 413 with modern log suites, of which 28 were cored. Geostatistical models (~25 million cells) were built with 413 wells for net pay, porosity, and permeability. These models were evaluated with sequential Gaussian simulation (sGs) and cloud transform algorithms on selected "sector" areas. The geostatistical models were upscaled for numerical simulation to allow for realistic process time. The final numerical simulation grid consisted of 240×140×20 cells with ~82,000 active.
The simulation model was built by integrating: 1) PVT data from nine wells, 2) 40+ samples of special core analysis data (relative permeability tables and capillary pressure tables), 3) completion data for 332 wells completed in UMBB, 4) 25+ years of allocated production and injection history, 5) more than 7,000 bottom hole pressure surveys, and 6) repeat formation tests from 43 wells.
Parallel processing with four to eight processors on an SGI ONYX machine significantly cut the run time. Integration and communication between simulation engineer, geostatistician, petrophysicist, and reservoir management team has led to considerable improvements in the simulation model. The combination of this process and intensive cross-disciplinary reservoir characterization resulted in significant time-savings in building the model and simulation history match time. The prediction cases are being utilized for future development planning for the UMBB.
Stimulation of a Producing Horizontal Well Using Enzymes that Generate Acid In-Situ - Case History
Authors: Harris Ralph E. , McKay Ian D. , Mbala Justin M. , Schaaf Robert P. 
Published: December 2007

Abstract
The Libwa 4 well offshore the Democratic Republic of Congo was stimulated in November 1999 using an enzyme-based process that generated acid in-situ. The results to date have been excellent. Well tests as high as 759 BOPD have been recorded after the treatment compared to less than 100 BOPD before the treatment.
Optimising Gravel Pack Performance in a High Rate Gas Development
Authors: Watson R. B. , Patey I. T. M. , Paveley C. , Rushworth P. 
Published: December 2007

Abstract
This paper discusses a reservoir conditions laboratory investigation into the fast track Easington Catchment Area (ECA) Neptune Development which was identified as requiring sand face completion design. During the front-end engineering design phase the initial case accepted for the platform and sub-sea processing facility was zero sand tolerance. Rock mechanical test results suggested that an open hole gravel pack was the best sand face completion option, however many formation damage mechanisms are known to be encountered during well operations.
The emphasis of the paper is to explain an investigation of the design phases of a sand face well completion under laboratory conditions. Therefore, each phase of laboratory testing looked at identifying and reducing formation damage mechanisms prior to well operations. To aid in interpreting permeability results and identifying damage mechanisms, dry and cryogenic Scanning Electron Microscopy (SEM) analyses were performed on samples before and after testing. This interpretation was used to determine whether formation damage occurs within the gravel pack assembly and interfaces or within the core. The advantages of well-designed drilling mud can be ruined by a poor completion procedure. Therefore, throughout the development phase it was strongly emphasized that synergy between the drilling phase and completion was paramount. An operational strategy was then generated from the results, which led to the installation of the sand face completions with minimal formation damage.
After implementing the preferred drilling mud, displacement of the drilling mud, then the associated enzyme and acid treatments post gravel pack operations from the core study, the Neptune Well showed extremely low skins. This production data confirms the importance of laboratory analysis undertaken on representative core intervals as a well performance predictive tool.
Relative Permeability Modifiers: Myth or Reality?
Authors: Botermans C. Wouter , van Batenburg Diederik W. , Bruining Johannes 
Published: December 2007

Abstract
Water production from oil and gas wells is an increasing problem for the oil industry. Many solutions to the problem have been proposed and some techniques have been successfully introduced into operations. These successful techniques generally require well interventions to isolate target zones and to place the treatments. However, the associated costs may inhibit the treatments from being economic. A bullhead type chemical treatment that selectively reduces water production appears to be a more attractive alternative. These systems are known as relative permeability modifiers.
This paper focuses on relative permeability modifiers from a reservoir and production engineering perspective. The concepts behind relative permeability and its effect on hydrocarbon production and recovery are briefly discussed. Existing experimental data and history matching were used to obtain relative and modified relative permeability curves. Subsequently, these relative permeability curves were used to identify conditions where relative permeability modifiers can be used with potential for success.
Non-Linear Rock Compressibility in the Naricual and Los Jabillos Formations, El Furrial Field, Venezuela
Authors: Smith Richard , Bard Karen , Colmenares Rodolfo 
Published: December 2007

Abstract
The discovery of the El Furrial field in 1986 opened a new era of exploration and development in the eastern Venezuela deep basin. Current production from the field and two adjacent fields, Carito and Santa Barbara, is near 900,000 stb/D (stock tank barrels per day). Reservoir simulation has been used consistently since 1989 for reservoir management. Water injection, initiated in 1993, was identified in 1991 as a necessary process to maintain reservoir pressure above a critical asphalt flocculation pressure. Reservoir pressure below the flocculation pressure (6500 psi for 2% asphaltene content up to 8500 psi for 12%) results in significant and irreversible well productivity decline. A previously unrecognized variable in the production mechanism, necessary for the history match of observed reservoir pressure after initiation of water injection, was identified with reservoir simulation modeling. Investigation of fluid compressibility, aquifer support, and rock compressibility, identified that this variable was more important than previously assumed.
The method of analysis shows that standard Teeuw1 rock compressibility analysis is not appropriate. The method proposed by Anderson2 does. This paper focuses on the rock compressibility issue, the analysis of the data, and the method to include the results in reservoir simulation.
Effects of Temperature and Interfacial Tension in Different Production Mechanisms
Authors: Najurieta H. L. , Galacho N. , Chimienti M. E. , Illiano Silvia N. 
Published: December 2007

Abstract
The objective of this paper is to study the relative importance of two complementary production mechanisms as are the displacement with water and the natural imbibition, evaluating the influence of different temperature and interfacial tension conditions in the production rate and final oil recovery of laboratory experiments. The production mechanism by spontaneous imbibition has been associated historically with the production in naturally fractured reservoirs. However, heterogeneities and channeling effect, usually present in argentine not fractured reservoirs, indicate that imbibition mechanism contributes considerably to the oil productivity.
Evaluation of both mechanisms simultaneously (imbibition and displacement) by means of laboratory experiments is difficult. Therefore, displacement and imbibition experiments were accomplished separately. The displacement experiments with water were carried out at room temperature and at 60°C, while imbibition experiments were accomplished at 60 and 80°C. Both studies were made firstly with water and then with water and surfactant, reaching low interfacial tension conditions.
The experiments were designed to reproduce reservoir conditions as faithfully as possible, since the phenomena involved are highly dependent of the molecular composition of both fluids and rock. Due to this water, oil and rock of the same formation were used. The rock used for this study presents strong water wettability.
The displacement experiments with surfactant were accomplished using two different methodologies: a) beginning the injection of surfactant from the start of the displacement, b) beginning the injection of surfactant after the injection of one poral volume (PV) of water.
This second procedure was employed since generally, the projects of EOR are subsequent to projects of water injection.
It was observed that the final oil recovery increases with the aggregate of surfactant, independently of the injection starting time. The conclusions of this study can be summarized as follows.
The phenomenon of spontaneous imbibition turned out to be an important production mechanism in waterwet rocks. The use of surfactants and the increase of temperature favor the effect of the imbibition mechanism.
The efficiency of the displacement mechanism also improves with the decrease of interfacial tension and the increase of temperature.
A new method to characterize the degree of heterogeneity of the sample as well as the contribution of the imbibition mechanism is presented. The method is based in a cualitative analysis of Oil Recovery vs. Poral Volume (PV) experimental curves.
Finally, a new method to measure the imbibition diffussivity constant to describe the imbibition as a dispersive diffussion process is developed and applied to experimental data, giving a simplified alternative to the modeling of the imbibition process.
Estimating IPR Curves in Intermittent Gas Lift Wells from Standard Production Tests
Authors: Caicedo Sergio 
Published: December 2007

Abstract
Currently in Lake Maracaibo there are nearly 2000 wells on Intermittent Gas Lift (IGL) with an average production of 150 BPD, so a method to estimate the IPR curves in such wells is necessary and important. Considering that in IGL the bottom hole flowing pressure is an instantaneous value continuously changing, then the correct and precise way to determine the IPR curve is through a production test along with a downhole pressure survey. However, many times this method is not economically convenient in highly depleted wells, as it does in a typical intermittent gas lift well. Since there is no publication reported on this subject, the purpose of this work is to get the equations that relate Vogel's model with field data for IGL wells and a numerical method to solve these equations in order to obtain an IPR estimation. Through these equations more realistic values can be obtained, and therefore a better match can be reached between simulators’ outputs and field data. These equations will help the field engineer to properly analyze and design these types of wells.
A New Exploration Play in the southwestern Region of the Golfo San Jorge Basin
Authors: Cardinali Guillermo , Borderas Marcelo , Lucero Monica , Figari Eduardo 
Published: December 2007

Abstract
The Golfo San Jorge basin, located in the central Patagonia, is the oldest producing basin of Argentina. It is an intracratonic extensionla basin, where the first economic discovery took place in 1907.
In the sothwestern sector, the Cerro Piedra – Cerro Guadal Norte area has a surface of 1835 sq Km, and only one field in production, the Cerro piedra field that has a daily production of 330 cubic meters of oil and 44500 cubic meters of gas from 40 wells. The reservoir unit is the bajo Barreal formation, that belongs to the Chubut Group (K) and is part of the best known play of the basin. Though 2D seismic analysis and the use of special techniques, an AVO study was made that showed an interesting response in the P normal wave incidence and the fluid factor.
This way it was possible to discriminate the top and base of an important gas bearing zone in the seismic, with a good correlation in the field with the well logs. From this a new Play is recognized, the Patagonia Formation of Tertiary Age. It consist of sandstone deposit, oroginated in a marine environment, up to 35 m thick, that by wells, with a production of 165000 m3/day.
This discovery is a new case in the basin and makes up an interesting exploration play in this part of the basin.
Applications and Developments of Sequence Stratigraphy in Latin America: Synthesis of Exploration and Development Experiences in the Sub-Andean basins
Authors: Torres M. A. , Porta R. , Brisson I. 
Published: December 2007

Abstract
Applying sequence stratigraphy concepts to the interpretation of petroleum and depositional systems constitutes a fundamental approach for regional exploration and detailed development analysis. Distribution of reservoir, seal and source rock represent primary parameters in the definition of petroleum systems; description and weightiness of these components are critical in prospects; spatial distribution and architecture of rock facies are essential in appraisal and development of fields. Sequence stratigraphic concepts are a proven powerful tool that gives the analyst a competitive advantage when defining the hydrocarbon potential from a basin to a field scale project. It has proven particularly useful when looking at old plays or mature basins in the search for upside or new plays. Forward modeling and prediction of basin fill facies in data starved frontier areas has been another benefit from this technique. Application of the sequence stratigraphic tools is less obvious when dealing with terrestrial deposits dominated basins.
Subandean basins present a variety of evaluation scenarios from the mature to the unexplored exploration/development settings. A few examples of Repsol-YPF assets from the Eastern Venezuela basin; the Colombia Llanos basin; the Marañon and Ucayali basins in Peru and the Cuyo and Neuquen basins from Argentina are analyzed using these concepts.
Is it Possible to Reach a Detailed Upscaling From a Core-Old Logs Match? The Answer is Yes, If an Integrated Approach is Used. La Ceibita Field, Eastern Venezuela
Authors: Panesso R. , Barbato R. , Quaglia A. , Porras J. C. 
Published: December 2007

Abstract
La Ceibita field is located in the Oficina area in the Eastern Venezuela Basin. A total of 63 wells have been drilled, 48 (76%) with "old logs", run prior to 1968, only 15 (24%) have log runs between 1968 and 1982, including modern porosity logs. Production in the studied reservoir began in 1957, and 11 wells have been completed. A gas injection program was implemented in 1960 in order to maintain reservoir pressure.
The purpose of the study was to generate a detailed petrophysical model using a methodology based on rock type characterization, integrating core, logs, production data, and, geological and reservoir information, in order to optimize exploitation plans and validate reserves.
The petrophysical characterization aimed the definition of rock types, which were classified based on pore throat radius estimated from mercury injection capillary pressure data. Pore throat radii corresponding to a mercury saturation of 45% represented the dominant interconnected pore system. Ranges of rock types from mega to nanno porous were used to define flow units, with pore throat radius being the dominant control on permeability and flow capacity.
Due to the lack of modern porosity logs it was necessary to apply a methodology to estimate porosity from the short normal curve, which was related with core porosity. The detailed upscaling from core to log was performed using the relation found between pore throat radius obtained from cores and true formation resistivity from electrical logs in the key well. Once porosity and pore throat radius were known, permeability was estimated from the Pittman R45 equation, which relates pore throat radius with conventional porosity and permeability.
Cross sections and maps of rock type distribution were used to observe the lateral rock type variability and allowed to identify the areas with better rock quality. The combination of this information with sedimentary facies maps will help model the reservoir and select prospective areas for development.
Detailed reservoir upscaling by matching core and old log data will only be possible through the integration of geological, petrophysical and production data.
Gas Oil Color (ASTM) Inference with Neural Network in an Oil Refinery Distillation Column
Authors: Villamil C. , De Vincenti G. , Tumini N. , Masson F. , Agamennoni O. 
Published: December 2007

Abstract
The first operation in an oil refinery is the atmospheric distillation. To maximize the extraction of some products like Gas Oil, a proper set of on line analysis instruments is required. These kinds of instruments are not always available, especially in medium and small size processing plants.
Due to the fact that color is a limiting specification, it constitutes a restriction for production optimization. Availability in real time of a good value estimate is what allows work to be carried out permanently in operative conditions where the process is most beneficial.
In this work a Neural Network (NN) approach to infer the color is proposed. A feed forward NN structure is used to identify the non-linear mapping from available process variables to that property.
To acquire representative I/O data, a set of dynamic experiments (move test) was developed in the plant. After that, a rigorous analysis to select the set of input variables was performed. In this study, process engineer's knowledge as well as some mathematical tools were used to evaluate a minimum set of inputs. From this analysis, the set of forty-three available inputs is reduced to the eight most sensitive with respect to the color representation.
Furthermore, rather than represent the entire transformation from the set of inputs variables to the output variable by a single neural network function, we analyze the possibility of breaking down the mapping into an initial pre-processing stage followed by a parameterized neural network model.