bluuebunny/crossref_metadata_2025_split huggingface dataset:
Field Performance Analysis of Micellar Polymer Pilot Flood
Authors: Aguey Omar Jose 
Published: December 2007

ABSTRACT
This paper describes field operations with attendant problems encountered during a micellar polymer flood process in the Hxa sand of the Wilmington Field, California.
Problems encountered include completion techniques, extreme corrosion, emulsions of produced fluids, and field handling of polymer.
The micellar polymer flood described here is Marathon Oil Company's Maraflood (TM) process and was designed by Marathon after much laboratory and field testing. The project was co-sponsored with D.O.E. and the City of Long Beach with the goal of establishing a tertiary oil recovery technique applicable to unconsolidated oil sands typical of the California region.
The test pattern selected, after conducting several computer model studies, is a staggered line drive consisting of four injection wells and six producing wells, with all injectors backed up by a North South trending fault. The sand selected for this pilot is located in the watered-out area of the Hxa sand of the Upper Terminal V-B Pool. Selection was made because of sand thickness, uniform sand body, good permeability, and because it was a watered out area which would facilitate the project evaluation.
The pilot project includes a total oil sand volume of 596 acre-feet underlying an area of about ten acres ith an average net sand thickness of 58 feet (17.7m). The permeability to air is about 400 md. The residual oil saturation after water flooding is estimated to be 38%. Recovery to date is estimated to be 38% of the 445 M barrels (70749 m3) of oil in place at the beginning of this project. The incremental oil recovery is expected to be 176,000 barrels (27982 m3) at abandomnent time.
The importance of this test is not only to determine he validity of the process in watered out areas of the vast Wilmington Field, but to determine and overcome field operating problems associated with a micellar polymer flood.
New Integrated Applications Using T1 and T2 Modes of Magnetic Resonance in Tight Gas Reservoirs: A Case Study From Northern Mexico
Authors: Monroy Ayala Norberto , Muñoz Rogelio , Rico Raul , Palacios Cesar , Torne Juan Pablo , Leuro Jorge , Fam Maged 
Published: December 2007

Abstract
Petrophysical evaluation of the tight gas reservoirs in northern Mexico presents challenges for identifying overpressured gas zones when applying conventional techniques in laminated and fine grain sand zones. This paper presents case histories in which the magnetic resonance technology was used in its new T1 mode and describes the advantages of this new logging mode over the conventional T2 mode in gas reservoirs. The paper highlights the integration of all available petrophysical data for a particular field. This integration model compares the irreducible water saturation between the newly developed models, based on magnetic resonance data after its calibration to core, conventional logs, and production tests. Our integrated approach was used to analyze the data from different wells drilled in the field and to determine the best petrophysical parameters for any interpretation. The approach used was focused on identifying the best zones to be further evaluated, considering the different responses of all available log data from each well in the field.
Permeability was derived from the Coates model using the magnetic resonance data after its calibration to cores. Results were then compared to actual production. For those wells in which only standard MRI logging information was available, the model was used to calculate the permeability and compare it to actual cores. Production test results were also compared to the evaluation prognosis and used to fine tune the interpretation model. The model was then used in other wells in the area for which few conventional log data were acquired.
The integrated approach used with the new MRI acquisition technique benefits the operators by helping them to better evaluate and produce laminated tight gas reservoirs. The methods developed helps with making the right decisions regarding the need to acquire additional log data, with defining intervals for testing, and determining the size of the required hydraulic fracturing for production.
A Second-Order Mimetic Approach for Tracer Flow in Oil Reservoirs
Authors: Guevara-Jordan J. M. , Arteaga-Arispe J. 
Published: December 2007

Abstract
A new mimetic method for solving tracer flow equations in oil reservoirs is presented. This mimetic method is a formal extension and an improved version of standard finite differences schemes and it has three main advantages. First, its grid is a hybrid version of point center and point distributed grids, so the new method does not require ghost points in its formulation and implementation. Second, boundary conditions approximations achieves same order of convergence as inner nodes, it is well known that standard finite difference schemes convergence rate deteriorates at boundaries. Third, the new scheme satisfies Green-Gauss-Stokes identity at the discrete level, which guarantee that the scheme is fully conservative and represents correctly the physics properties of the problem. The new scheme was implemented to solve tracer flow equations in a reservoir and it was tested in a set of five spot problems. Numerical results show that the new scheme produces better approximations than standard finite difference simulators on coarse grids.
Production Optimization Using the Capillary Technology in the Loma La Lata Field
Authors: Cabral P. , Giérega C. R. , Costanza P. , Suriano A. A. 
Published: December 2007

Abstract
Ever since its discovery in 1977, the Loma La Lata field, located in the Neuquén basin, has been considered one of the most important gas fields in South America.
During the last decade, the progressive reduction in the reservoir pressure has led to successive changes in the field's operation conditions: from high to medium pressure, and, most recently, to low pressure.
As the reservoir pressure depletes, the subsequent reductions in the gas velocities bring about changes in the flow regimes and the increasing liquid flow rates. These liquids produced at the wellbore and/or generated by vapor condensation through the production string, contribute to increase the pressure drop along the tubing as well as the flowing bottomhole pressure, and will eventually reduce or prevent production.
In most cases, not only does liquid loading arise as a consequence of these changes in operation conditions, but also other production problems such as mineral scales and organic deposits, and the difficulty to implement corrosion prevention conventional batch treatment programs aimed at extending the life of the production strings.
In addition to the above, the increasing hydrocarbon demand, Argentina's energy policy and economical restrictions are also matter of relevance when it comes to implementing conventional solutions that imply several shutdown hours per treated well.
The aforementioned problems have encouraged the operating and services companies to search for technological alternatives providing not only technical solutions but also economical benefits.
After one year since a novel capillary string system that allows for the injection of chemical products, and/or the deployment of special devices such as memory gauges, at the desired depth was introduced in the country, the results obtained in several tests show a very promising future.
This paper summarizes the first-year results achieved using the capillary string technology as a tool for production enhancement and optimization in the Loma La Lata field.
Static and Dynamic Models of Formation Water in Sincor Area, Orinoco Belt, Venezuela
Authors: Marcos J. , Pardo E. , Casas J. , Delgado D. , Rondon M. , Exposito M. , Zerpa L. , Ichbia J. , Bellorini J. 
Published: December 2007

Abstract
Sincor is a strategic association between PDVSA, Total and Statoil, committed to the production, upgrading and commercialization of extra heavy oil from an area covering over 325 Km2 in the Orinoco Belt (Figure 1).
The Sincor area is composed of a series of stacked unconsolidated sand-shale reservoirs with good petrophysical properties. The depositional system can be divided in two main parts, Deltaic and Fluvial. Fluvial sands, mainly stacked braided channels, represent the bottom part of the reservoir. Deltaic sands go from distributary channel and mouth bar to point bar and crevasse splay.
Drilling of vertical observation wells and a testing campaign started at the end of 1999. In well tests, anomalies in water salinity values were observed: an aquifer salinity of 2300 ppm, while some wells produced water at 15000 ppm. At that time, high values were considered measurement problems.
In 2001, the first horizontal producers started to cut water with similar high values to those observed in some well tests. Since then a multidisciplinary study was launched aiming at defining and characterizing all water sources using well tests (15 vertical wells) and water production data (150 horizontal wells). This information has then been integrated with geological interpretation and reservoir characterization.
In this paper a static model is developed using well test information from the area. The model explains why different ranges of water salinities were observed in the oil and water zones. This model was corroborated qualitatively with log information.
Dynamic data confirmed and detailed further the initial model. An exponential decrease of water salinity is generally observed with increasing water production or water cut. This phenomenon is explained by probable water influx in the form of fingering from the low salinity aquifer continously displacing high salinity formation water. The exponential curve shape would depend on the tortuosity and length of the path between the water and the produced oil zones.
Static and dynamic data are consistent and confirm our model of water production mechanism observed in the field.
Enhanced Mass Transfer of CO2 Into Water and Oil by Natural Convection
Authors: Farajzadeh R. , Delil H. A. , Zitha P. L. J. , Bruining J. 
Published: December 2007

Abstract
Global warming has increased interest in quantification of the dissolution of CO2 in (sub)-surface water. CO2 is present above the surface water. Dissolution of CO2 into water (or oil) causes a density increase, with respect to pure water (or oil). This density effect causes natural convection, which enhances the mass transfer rate across the interface. This article describes a series of experiments performed in a cylindrical PVT-cell, where a fixed volume of CO2 gas was brought into contact with a column of distilled water. The results show that the mass transfer rate across the interface is much faster than predicted by Fick's law. This mass transfer rate increases with increasing initial gas pressure. However, in the long term the mass transfer rate is controlled by diffusion alone. The long term behavior, therefore, allows the determination of the diffusion coefficient. Its value agrees with values presented in the literature. A similar mass transfer behavior was observed for the experiments with an oil phase (n-C10 and n-C16). Therefore analogous experiments using oil instead of water are valuable for enhanced oil recovery projects.
A theoretical interpretation of the observed effects has been proposed, based on diffusion and natural convection phenomena. The Rayleigh number is of the order of one million whereas the Schmidt number is of the order of five hundred. The ensuing equations have been solved numerically, using the finite volume approach. There is qualitative agreement between the experiment and the numerical results and similar to the experiments the mass transfer becomes diffusion like in the long term.
An Approach to Optimum Facility Siting
Authors: Mathur Anil , Haire William Mullen , Earhart James W. , Weaver Susan E. 
Published: December 2007

ABSTRACT
This paper describes a heuristic approach to Production Facility siting and optimal pipeline routing to connect wells to Production Facilities. The pipe sizes for the production, lift gas and water injection systems were calculated and included in the optimization. Production Facility siting, based on production lines alone, is not optimal.
Effects of Stress on Fracture Properties of Naturally Fractured Reservoirs
Authors: Chacon Abel , Tiab Djebbar 
Published: December 2007

Abstract
This paper analyzes the effect of stress on the rock properties fracture and matrix compressibilities, fracture and matrix porosities, and permeability in naturally fractured reservoirs (NFRs).
In NFRs, fluids are stored inside the matrix pore space and inside the fractures of the rock. The reservoir characterization parameter indicating the volumetric fraction of fluids deposited inside the fractures is the storage capacity ratio, which is function of the fracture and matrix porosity, and fracture and matrix total compressibilities. Due to the difficulty to obtain these values, in reservoir engineering computations such as pressure transient analysis and reservoir simulation, among others, it is generally assumed that the matrix and the fracture total compressibilities are equal. This induces a big uncertainty in the estimation of the storage capacity ratio and leads to a wrong estimation of the volume of fluids inside the fractured rock.
Changes in pore pressure due to production or injection of fluids affect the effective reservoir in-situ stress. The mechanical behavior of the fractured rock and its effects on the rock properties permeability, porosity and compressibility in the matrix and fracture frames are analyzed using the elastic properties bulk modulus and normal compliance of the fracture. These properties can be obtained from petrophysical core analysis or multi-component seismic interpretation, and linked to pressure transient analysis through the storage capacity ratio equation. A step-by-step procedure of the analysis is presented and illustrated with an example for quantifying the effects of changes in effective stress on the fracture and matrix compressibilities.
Economic Modelling of an Oil and Gas Project Involving Carbon Capture and Storage—Snøhvit LNG Field (Barents Sea, Norway)
Authors: Negrescu Matei 
Published: December 2007

Abstract
The Snøhvit LNG project developed by Statoil and partners in Norway, is used as an example to describe how the Carbon Capture and Storage (CCS) component of an oil and gas project can be isolated, modelled and analysed from an economic point of view. The Snøhvit development, due to start production in late 2007, will involve a CCS component from day one. Approximately 700,000 tons of CO2 captured from the liquefaction plant will be reinjected every year in an underground formation offshore. Furthermore there are interesting alternatives for CO2 capture from the on-site power plant and for the use of CO2 for EOR in a nearby oilfield, leading to several future development scenarios for CCS at Snøhvit.
Different development scenarios for CCS are analysed to select the best development option. The economic modelling framework will also be used to assess the impact of the uncertainties on the project economics.
The analysis identifies that a key driver for the profitability of the project is the legislative setting for CCS. The involvement of the government is very important for the viability of the project, which needs a strong incentive, as the current CO2 tax scheme or an emission trading scheme with strict allocation of emission targets. Under such conditions a CCS project such as Snøhvit becomes a win-win situation: economically profitable for the operator and environmentally friendly.
From a broader perspective, addressing the economic and legislative uncertainty currently surrounding CCS projects for the oil and gas industry is crucial because this represents the main limiting factor for the further development of such projects. It is therefore essential that economic modelling tools such as the framework described in the present work become industry standards so as to ensure that projects which could be profitable for both the operator and the environment are not abandoned by pure lack of analysis ability.
Thermodynamically Consistent Analytical Approach for Streamline Simulations of Multicomponent Hydrocarbon Reservoirs
Authors: Podgornova Olga , Myasnikov Artyom , Bratvedt Kyrre , Rykov Yuri , Koldoba Elena , Koldoba Aleksandr 
Published: December 2007

Abstract
One of the most challenging problems for reservoir simulation is the computation of a multicomponent flow of compressible fluids in porous media with mass exchange between phases. In this work, we consider a streamline method for two phase compressible multicomponent flows in hydrocarbon reservoirs. We prove, that even with standard PVT procedures performed at each time step at each spatial point, streamline technology maintain its better scaling ability than traditional finite difference/volume technologies. However, we went further and have treated the thermodynamics in terms of Koldoba & Koldoba approach7. The model allows for receiving phase equilibrium curves and other thermodynamic functions in analytical form, thus it achieves the thermodynamic agreement of system and greatly reduces the required computing resources.
Relative-Permeability Modifiers and Their Use in Acid Stimulation in HP/HT Low-Permeability Carbonate Formations: Offshore Mexico Cases
Authors: Duverney Eduardo Soriano , Robles Fernando , Lopez Antonio Inda , Steffani Octavio 
Published: December 2007

AbstractSuccessful acid stimulation requires a method for diverting an acid across the entire hydrocarbon-producing zone. Because most producing wells are not homogeneous and contain sections of varying permeability, being able to completely acidize the interval is a major problem. This paper describes the use of a new low-viscosity system that uses a relative permeability modifier (RPM) that diverts acid from high-permeability zones to lower-permeability zones and inherently reduces formation permeability to water with little effect on hydrocarbon permeability. This system has been used effectively offshore Mexico with success for more than two years. The cases presented in this paper show the first application in a low-permeability carbonate formation where oil production was increased significantly compared to previous traditional acid treatments using conventional diverters.The other important feature of this work is that the downhole conditions were high-pressure/high-temperature (HPHT). Details from the jobs using this new RPM acid-diversion system will be presented showing pre- and post-job production results.
The Effect of Lateral Anisotrophy on Flood Pattern Dimensions and Orientation
Authors: McElroy Stacy L. 
Published: December 2007

ABSTRACT
This paper compares different flood pattern orientations and dimensions for isotropic and anisotropic reservoirs in order to determine the optimum waterflood pattern in the presence of directional permeability. This was accomplished by simulating the reservoir performance for several patterns with a 5-point black oil simulator. The patterns simulated include the: 1) 5-spot, 2) inverted 9-spot, 3) modified 9-spot (an inverted 9-spot pattern with two producing wells eliminated), and 4) direct line drive.
For simplification, unit mobility ratio and miscible displacement were used to model the displacement of oil by water, although the conclusions are identical for a mobility ratio different from one and an immiscible displacement. Each pattern was tested with the dimensions being both square and elongated (four times the length in one direction). Each of these sets of patterns were simulated as isotropic and anisotropic reservoirs. The patterns were elongated in the direction of and in the direction opposite to the high permeability trend.
Included is a discussion of results of each pattern tested and conclusions as to the optimum waterflood pattern for anisotropic reservoirs. These conclusions may be applied to any reservoirs having directional permeability. These results may be realized with any injection scheme such as CO2 injection, natural gas injection and steam flooding.
An Experimental Investigation of Three-Phase Flow of Water-Oil-Gas Mixtures Through Water-Wet Sandstones
Authors: Saraf Deoki N. , Batycky James P. , Jackson Clive H. , Fisher Douglas B. 
Published: December 2007

ABSTRACT
Three-phase relative permeabilities to water-oil-gas mixtures have been measured both under unsteady-and steady-state conditions through fired Berea sandstone. A computer-based photometric device was used for monitoring fractional flow of displacement fluids. An extension of the Welge-JPN method to three-phase flow was used for the calculation of relative permeabilities from displacement data. Several saturation histories relevant to petroleum reservoir exploitation were examined. Steady-state measurements with saturation histories similar to those in the unsteady-state experiments were made on the same core to enable comparison of the results.
Water relative permeabilities were found to depend only on water saturation and were practically independent of the saturation histories considered. Gas relative permeabilities depended on the total liquid saturation; the components of the liquid being of no concern. They depended strongly, however, on the direction of saturation change of the gas phase.
Oil relative permeabilities seemed to depend on saturations of all the phases present. Although the direction of oil and water saturation change did not influence oil relative permeabilities significantly, the decreasing gas saturation resulted in higher values as compared to those when the gas saturation was increasing. This seems to suggest that trapping of gas facilitates more free movement of oil. Predictions made by the use of Stone's two models yielded lower values of relative permeability to oil when compared to the experimental results, suggesting the inadequacy of these models even for the strongly water-wet rocks used in the present study.
Steady-state measurements of three-phase relative permeability yielded results similar to those obtained by the displacement method for both oil and water. However, owing to a different trapping mechanism, the gas phase relative permeability showed a much weaker dependence on the direction of gas saturation change under steady-state conditions when compared to the displacement process.