bluuebunny/crossref_metadata_2025 huggingface dataset:
A Field Methodology to Estimate the Zone of Maximum Probability of Asphaltene Precipitation Occurrence
Authors: Avila C. , Russo A. , Flores E. , Hidalgo O.
Published: December 2007

Asphaltenes precipitation is one of the major operational problems affecting oil production in the Northern Monagas fields of Eastern Venezuela. Being a phenomena that depends primarily on crude composition, pressure and temperature, it may occur inside the pore space, downhole along the producing strings, at the well head, inside flow lines, separators and gas treatment plants. In most cases, the cleaning of pipes and production strings is done through chemical treatment. For downhole treatment, coiled tubing or snubbing units have to be used, thus increasing production costs.

A field methodology based in the influence of pressure in asphaltenes precipitation has been designed and implemented to estimate the zone of maximum probability of asphaltenes precipitation. Nodal analysis is applied to determine pressure versus depth behavior at the well for different operational conditions. Gross composition chemical analysis and asphaltenes dispersion curves of the crude oils are required. Knowing the saturation pressure and the flocculation onset pressure, the methodology allows the determination of the most probable range of depths at which asphaltenes precipitation will occur.

The purpose of this methodology is to determine the optimum operational conditions that maximize production at minimum risk of asphaltenes precipitation, as well as to select the better preventive measure for each particular case, thus maintaining overall control of the asphaltenes plugging problem.

In this work, field applications of the methodology are shown. Depending on the depth range of asphaltenes precipitation occurrence, reperforation of the producing interval, hydraulic fracturing or chemical treatment is recommended. Application of the methodology is becoming routine in the Northern Monagas fields. An expert system based on the methodology is under development to extend its application throughout the area.
Integrated Petrophysical Model, C4 and C5 Reservoirs, VLA-6/9/21 Area, Block 1, Lagomar, Lake Maracaibo, Venezuela
Authors: Madariaga M. , Garcia E. , Barbato R. , Quaglia A. , Porras J. C.
Published: December 2007

Reservoirs C4 and C5 belong to the VLA-6/9/21 area of the Lagomar Segregation, and are located in the East Flank of the Block I, Lagunillas field, Lake of Maracaibo Basin, Western Venezuela. The C sands correspond to the Misoa formation of Eocene age. For the present study, 25 wells of the area were selected, 12 of which belong to a special Integral Field Laboratory, and have enough information that allowed the generation of a model that can be extrapolated to other wells in the field. Using all this information, certainty maps for each reservoir were constructed. Pore throat radius was estimated from porosity and permeability data from conventional core analysis, along with capillary pressure data. Winland's equation, an empirical relationship between porosity, air permeability and pore throat radius corresponding to a mercury saturation of 35%, was used for reservoir C5. In 1992, Winland's work was modified by Pittman, and for reservoir C4, the R45 Pittman equation was applied. Cementation and saturation exponents (m, n) for C4 and C5, were determined from core analyses. The resistivity of the formation water (Rw) was estimated from chemical analyses and by the SP curve method. Clay volume (Vsh) was obtained using Larionov's tertiary rocks model, which correlated well with X-Ray difraction analyses. Once the key wells were evaluated using the Waxman-Smits water saturation model, which resulted in a good match between core and log data, the evaluation was extrapolated to the other new and old wells of the area. Five different rock types were identified: Mega, Macro, Meso, Micro, Nanno, and were used to construct cross-sections showing their lateral distribution. Flow units were identified using the Modified Lorenz Plot and the Vertical Flow and Storage Diagram. Rock type areal distribution maps were also constructed, and have an excellent agreement with the sedimentary facies maps obtained from the sedimentological study.
Designing a Mobility Control Foam for Western Venezuela Reservoirs: Experimental Studies
Authors: Romero C. , Valero E. M. , Alvarez J. M. , Romero O. M.
Published: December 2007

This paper presents the results of laboratory tests, performed in a mobility control foam design for Western Venezuelan Reservoirs. In this operational area, two Water Alternate Gas (WAG) injection projects are currently under way using natural gas, but they are expected to change to nitrogen.

The tests presented in this paper were performed mainly with nitrogen, although a final displacement test was designed using fluids that are currently under use in the Lagocinco VLE WAG injection project. The final goal was to achieve a mobility control foam, for gas profile modification in WAG injector wells.

The experimental work was divided in several steps: (1) preliminary screening tests for adequate surfactant selection; (2) mobility reduction tests at average Western Venezuelan conditions; (3) adsorption tests; and (4) a final displacement test in a composite reservoir core using fluids and conditions for the Lagocinco VLE Field.

The selected surfactant for the foam was an alpha oleofinsulfonate (AOS) combined with a fluorinated surfactant for added stability to oil. Surfactant-gas co-injection was used in all core displacement tests as injection scheme. The foam achieved a Mobility Reduction Factor (MRF) of 100 at average Western Venezuelan conditions, while at Lagocinco VLE conditions the MRF values were as high as 800.
ASP System Design for an Offshore Application in the La Salina Field, Lake Maracaibo
Authors: Hernández Clara , Chacón Larry J. , Lorenzo Anselmi , Baldonedo Abel , Jie Qi , Dowling Phillip C. , Pitts Malcolm J.
Published: December 2007

The La Salina Field in the eastern coast of Lake Maracaibo, Venezuela, was designated as a Laboratorio Integrado de Campo (Integrated Field Laboratory, IFL) by PDVSA to evaluate the potential application of different EOR processes. One of the main goals at La Salina FIL was to evaluate the alkaline-surfactant-polymer (ASP) technology potential in an oil reservoir near the end of its waterflood life.

La Salina produces a medium gravity crude oil (25 °API) from LL-03/Phase III Miocene reservoir at 915 m (3,000 feet). The feasibility of applying the ASP technology was based on a series of experiments including fluid compatibility, chemical thermal stability, spontaneous emulsification, interfacial tension between crude oil and ASP solution, chemical retention in the porous media, and physical simulation using reservoir core samples. The laboratory design involved twenty-three commercial surfactants, five polymers, and two alkalis. Interfacial tension reductions in excess of 25,000 fold were observed for a variety of ASP solutions. Type II- and Type III spontaneous emulsification, both considered optimum, were observed. Linear coreflood results indicate that high molecular weight (partially hydrolyzed polyacrylamide) polymers can be injected into La Salina sand at about 800 mg/L. Radial sandpack corefloods produced an average oil recovery of 46% OOIP with water injection. Injection of 30% pore volume of ASP solution followed by 30% pore volume of polymer drive solution produced an average additional 24.6% OOIP for an average total oil recovery of 70.2% OOIP.

The design of the injection plant for La Salina is a challenging task since this will be the first offshore application of the ASP technology in the world. Preparation and transport of a phase stable ASP solution, through the injection lines and into the reservoir, that has the designed chemical concentrations and physical characteristics are crucial for a successful project. The initial decision for the plant design was to use an existing platform instead of a barge for construction of facilities. As a result, critical parameters such as: treatment sequence, equipment footprint, and storage space for injected and treatment chemicals were considered.
The Study of Oil/Water Separation in Emulsion by Membrane Technology
Authors: Fernández Laura G. , Soria Carlos O. , García Tourn Carolina A. , Izquierdo María Sánchez
Published: December 2007

Water treatment plants use conventional processes like hydrocyclones and air up-floating equipment to separate oil from water. However, these devices are not effective at removing oil drops with small diameters.

In this work, the use of membranes to treat oil-water emulsions is analyzed. The performance of microfiltration ceramic and ultrafiltration polysulfone membrane in laboratory scale is studied. Drop of less than 50 μm diameters is the subject of our interest.

The new European standards will require less than 10 ppm hydrocarbons. Such standards could easily be met by using membrane technology. The most serious limitation of this technology is a continuous permeation flux decrease due to fouling, which is associated with different membrane-solute interactions, operation conditions, transmembrane pressure, temperature, etc. Emulsions with different concentrations (1000, 500 and 250 ppm) and different droplet sizes are studied. These emulsions are synthesized and characterized in the laboratory.

The results found for different nominal molecular weight cut-off, membrane materials and operation condition permit to analyze whether this alternative technology is suitable to solve a separation problem, which is of great environmental interest.
Resolution of Environmental Passives in the Refinery Lujan of Cuyo of Repsol YPF S.A.
Authors: Fernández L. , Vera F. , Ercoli E.
Published: December 2007

The objective of the following work is to show the different techniques applied for the recovery of passive environmental and the convenience of the application of each one in the different cases. In the Refinery of Lujan of Cuyo of Repsol - YPF S.A. were existing environmental passives of different characteristics. One of them was consisting of pools to sky opened without waterproofing that was containing a volume of flowing material of approximately of 20000 m3 of mud contaminate with heavy and light hydrocarbons, phenol, exhausted caustics, mercury, lead and other metals in high concentrations. The other was consisting of a surface of approximately 50000 square meters of contaminated soils with hydrocarbons originating from funds of tanks and dry muds resulting of the continuous centrifugation of muds. Complying with the commitment assumed his environmental policy of remedying the passive, the Refinery beginning an investigation program to find the more convenient alternatives for each case. At the moment of considering the alternatives of solution they have had into account technical, environmental and economic aspects. After analyzing the various existing technologies was opted for using two types of different treatments as compared to the different realities that was presenting each case. In the first case was opted for the stabilization technique that was developed in the area of the refinery, in base to tests accomplished at plant level pilot. Surpassed this stage were begun the tests to industrial scale what permitted to solve the problem in a period of 6 months. In the second case was opted for the use of bioremediation techniques: landfarming and aerated accumulation. These techniques were developed along with the National University of Cuyo. In either cases it is accomplished a monitoring of the results with the University and the organs of environmental control, being obtained successful results, with the recovery of the discussed soil.
Physical and Numerical Simulation of an Extra-Heavy Crude Oil Downhole Upgrading Process Using Hydrogen Donors Under Cyclic Steam Injection Conditions
Authors: Ovalles Cesar , Martinis Jorge , Pérez-Pérez Alfredo , Cotte Edgar , Castellanos Luis , Rodríguez Héctor
Published: December 2007

Physical simulation experiments of a Downhole Upgrading Process showed that use of a hydrogen donor additive (tetralin) in the presence of methane (natural gas) and the mineral formation under steam injection conditions (280°C and residence times greater than 24 h) led to an increase of at least three degree in API gravity of the treated Extra-Heavy Crude Oil, three-fold viscosity reduction and, approximately, 8% decrease in the asphaltene content with respect to the original crude. In the present work, a continuous bench scale plant was used at different temperatures (280-315°C) and residence times (24-64 h) for carrying out kinetic studies. A reaction model involving four pseudo-components (light, medium, heavy and asphaltene fractions) was used and the kinetic parameters (pre-exponential factors and activation energies) were determined. Using these data, compositional-thermal numerical simulations were carried out and validated using the bench scale data. The results showed a good match between the calculated and experimental °API gravities of the upgraded crude oil (average relative error 4%).

Using the previous model, the Downhole Upgrading Process was numerically simulated under cyclic steam injection conditions (injection of 2500 bbl/d of 1:1 steam/tetralin with 75% quality steam) for 20 days, followed by 10 days of soaking period) in a typical Orinoco Basin reservoir (9°API). The simulation runs showed the production of 12°API upgraded crude oil, accumulated over a 100 day-cycle. However, a reduction in the percentage of conversion of tetralin was observed (0.8%) in comparison with the bench scale experiments (3%), which was attributed to gravitational segregation of the steam coupled with low mixing efficiency of the hydrogen donor with the extra-heavy crude oil at reservoir conditions.
Rigorous Modelling of Fractures in a Porous Medium
Authors: Saghir M. Ziad , Edali Mohamed A. , Islam M. R.
Published: December 2007

While fractured formations are possibly the most important contributors to the oil production worldwide, modelling fractured formations with rigorous treatments has eluded reservoir engineers in the past. To-date, one of the most commonly used fractured reservoir model remains the one that was suggested by Warren and Root more than three decades ago. In this paper, a new model for fractures embedded in a porous medium is proposed. The model considers the Navier Stokes equation in the fracture (channel flow) while using Brinkman equation for the porous medium. Unlike the previous approach, the proposed model does not require the assumption of orthogonality of the fractures (sugar cube assumption) nor does it impose incorrect boundary conditions for the interface between the fracture and the porous medium.

The proposed model is derived through a series of finite element modelling runs for various cases using Navier Stokes equation in the channel while maintaining Brinkman equation in the porous medium. Various cases studied include different fracture orientations, fracture frequencies, fracture width, and the permeability of the porous medium. Finally, a series of numerical runs also provided validity of the proposed model for the cases for which thermal and solutal effects are important. Such a study of double diffusive phenomena in the context of fractured formations has not been reported before.
New Technique for Proppant Flowback and Improved Fracture Conductivities
Authors: Rae Phil , Briggiler Norberto , Di Lullo Gino , d'Huteau Emmanuel
Published: December 2007

Flowback of fracturing proppant during production is a common problem. The consequences of this can be extremely serious. Loss of fracture conductivity can occur due to reduced width, which can be further compounded by partial plugging of the pack by proppant fines. The latter are produced by non-uniform loading on the proppant with resultant failure and crushing. The produced solids can wreak havoc with both downhole and surface equipment, eroding chokes and nipples, plugging flow lines and filling separators. In the case of sub sea wells, the problems are even greater and can compromise well security. Since the 1980's, the standard solution applied for prevention of proppant flow back has been the use of curable resin coated proppant. While this approach has met with some success, it is far from perfect. The use of RCP's can cause fluid compatibility problems and can interfere with well clean up. Such problems have prompted resin manufacturers to modify their products and have also opened the door for the introduction of new technologies. Newer developments have included the use of small fibres to try to bind the proppant pack together or heat-sensitive plastic film to partially encapsulate clusters of proppant. These materials have reportedly been used with some success but concerns have been raised with regard to their effect on fracture conductivity, amongst other things.

This paper describes the current methods in use and presents a new system that actually enhances fracture conductivity and minimises embedment and width-loss, while simultaneously helping prevent proppant back-production.
First Massive Hydraulic Fracturing Treatment in Argentina
Authors: Antoci Juan Carlos , Anaya Luis Antonio
Published: December 2007

In the last two decades, it was usual practice in the oil industry to carry out massive hydraulic fracturing works to stimulate wells with great-heighten layers of interest and/or low permeability sands.

Argentina has had no opportunity so far to make a stimulation work of this type, mainly because of the absence of a layer meeting the principal characteristics needed to carry out a job of this size, considering the lack of equipment required by a service company to face the magnitude of the work in question.

In the year 2000, Pan American ENERGY, a BP Amoco subsidiary, made exploratory works on a sand formation of interest that met the adequate characteristics to try and develop this kind of job.

This paper shows how operator and service company designed this treatment in a team work and how this job was accomplished and came to be the largest stimulation treatment successfully done in Argentina to date. This kind of jobs can open a new way to handle tight gas zones in Argentina.
Crosslinked Methanol: Analysis of a Successful Experience in Fracturing Gas Wells
Authors: Antoci Juan C. , Briggiler Norberto J. , Chadwick Jorge A.
Published: December 2007

Over 200 hydraulic fracturing jobs using crosslinked anhydrous methanol as fracture fluid, have been performed in Argentina since the introduction of the technology in the country in 1992. Initial development of the crosslinked methanol was intended to reduce formation damage caused by swelling clays and capillary blockage related to high fluid surface tension when stimulating gas reservoirs. This paper summarizes the basic development of the technology, presenting recent findings on lower friction pressure, proppant carrying properties, environmental concerns solutions and larger temperature range of application. It also reviews the acquired experience, focused on its application in the field with the most extensive usage in Argentina, and it includes references to the broadening of the span of applications to different gas bearing rocks, higher temperatures and deviated wells; and a brief discussion on safety and cost issues.

A study of the factors influencing the gas flow initiation stress (FIS) at fracture faces after being invaded by fluid filtrate is presented, supported by laboratory tests comparing water base fluid against methanol base fluid.

Finally, the influence of fluid vaporization is presented as a key mechanism unique to methanol that overcomes the effect of FIS (both at the fracture faces and in the propped fracture) in reducing effective fracture length. Methanol vaporization explains that the effective fracture lentgh will approach total propped length resulting in increased early time productivity and ultimate gas recovery.
Stimulation with Hydraulic Fracture of an Upper Cretaceous Fissured Tuff System in the San Jorge Basin, Argentina
Authors: d'Huteau E. , Breda E. , Homovc J. , Petrelli G. , Saavedra B.
Published: December 2007

The siliceous tuff of the Castillo Formation (Upper Cretaceous), shows a high degree of deformation in areas adjacent to faults, generating fissured systems with capacity to drain the hydrocarbons present in the residual rock porosity. Based on the results of the fracture spatial distribution analysis and on the direction of the preferential flow, tests were designed to increase the recuperation of oil from these systems, using hydraulic fractures.

A reprocessing of a diplog with new algorithms, allowed to determine the direction of the natural fractures present in the rock, and to determine the direction of the in situ stresses, and so the expected direction of an induced hydraulic fracture. TCP, directioned with a gyroscope, was used to perforate in the plane of the maximum stress.

In the past, attempts to hydraulically fracture this reservoir gave very poor results, with - in most of the cases - premature screen out due to the existence of multiple fractures. The total pumping of fluids was considered as a fact for the low production due to hydraulic fractures parallel to the fissures plane and/or poor connection between the induced fracture and the wellbore.

In the studied well two different intervals were hydraulically fractured, one successfully, the other not as expected.
Studies on The Effects of Solvents on The Physicochemical Properties of Automotive Gasoline
Authors: Teixeira L. S. G. , Guimarães P. R. B. , Pontes L. A. M. , Almeida S. Q. , Assis J. C. R. , Vianna R. F.
Published: December 2007

In Brazil, some substances are not allowed to be added to commercialised fuel, because their use would imply tax evasion, since these substances are not taxed. Therefore, monitoring the quality of commercialised fuel is a very important issue. This work presents and discusses the influence of the addition of different proportions of n-paraffin, mainly n-hexane, kerosene and diesel oil on the distillation profile and octane number of automotive gasoline. The results show that it is possible to add non-allowed substances while keeping the automotive gasoline within specification limits. This means that much research should be undertaken in order to establish methodologies that can allow inference of the presence of such substances through physicochemical analyses, even at low concentrations.
Government Share and Economic Analysis: Case Study of Campos Basin, Brazil
Authors: Barbosa Décio H. , Gutman José
Published: December 2007

The purpose of this paper is to evaluate the economic potential of oil fields located in deep-water Campos basin, under different cost structure and price scenarios, via-à-vis the government revenue share resulting from the current fiscal terms introduced by the new Petroleum Law. The outcomes show that the Brazilian fiscal regime is competitive in a world basis and the analysed oil fields are economically attractive under the scenarios most likely to happen.
Significance of Project Risking Methods on Portfolio Optimization Models
Authors: Tyler P. A. , McVean J. R.
Published: December 2007

Efficient frontier theory is gaining acceptance as a part of the portfolio analysis process in the petroleum industry. One of the major difficulties companies encounter in creating corporate efficient frontiers is in representing project level risks in a corporate consolidation of value. Full stochastic evaluations require the management of huge quantities of data. As a result several current solutions use multiple discrete outcomes to represent any given project, rather then a complete stochastic distribution. This paper evaluates the differences resulting from using these two approaches to project risking. By examining the optimized portfolio results and the resultant efficient frontier, we are able to draw direct conclusions about the added value attributable to detailed Monte Carlo based evaluations. Since price is the source of most correlation between projects, the investigation was done with and without price as an input variable. It was discovered that the differences between the stochastic and discrete outcome evaluations are not significant when price uncertainty is neglected, but the inclusion of price leads to significant differences if the resulting correlation is not accounted for.
Field Development Decision Making under Uncertainty: A Real Option Valuation Approach
Authors: Dezen F. , Morooka C.
Published: December 2007

Real Option Valuation (ROV) has been developed to assist the decision making process for capital investments, whether R&D programs for new drugs, new petrochemical plants, leases of offshore and onshore acreage, etc (ref 1, 2, 3). The proposed work herein demonstrates that the ROV can be a useful technique and toolbox for the selection of different field development concepts and alternatives. Instead of using discounted cash flow (DCF) techniques only, the paper explains the possibility of adding ROV as part of the decision analysis process and the contributions that this approach will accomplish.
Acoustic and Signal Processing Techniques To Estimate Rock Properties Through Casing: Preliminary Results
Authors: Garcia-Osuna F. , Podio A. L. , Hixson E. L. , Gregory A. R.
Published: December 2007

This paper reports preliminary results of the development of acoustic and signal processing techniques to estimate rock properties through casing. In general, the major factors influencing compressional (P) and shear (S) wave velocities of unconsolidated and consolidated sedimentary rocks are porosity, bulk density, and effective stress. The acoustic impedance of the viscoelastic porous media behind the cemented casing will also depend on these factors, being higher for rocks under water or oil-saturated conditions than for rocks under gas-saturated condition. Stronger local-borehole compressional-wave reflectivity is expected from gas-rock reservoirs than from water or oil-rock reservoirs. In the case of the wet-Berea sandstone, the formation acoustic impedance is similar to the acoustic impedance of the cement layer. Experimental and theoretical studies of ultrasonic wave transmission and reflection for cemented casings and steel-plates with cemented sedimentary rocks were undertaken. Results provide a quantitative means to use acoustic energy to evaluate pore fluid saturant and detect gas, oil, and water interfaces through casing. A time and frequency domain analysis of a selected portion of the reflected signal at normal and oblique incidence is carried out. Laboratory measurements of ultrasonic wave attenuation and penetration into the rock formation through casing are also described and discussed.
Oil Displacement by Water in Vuggy Fractured Porous Media
Authors: Cruz-Hernández J. , Islas-Juárez R. , Pérez-Rosales C. , Rivas-Gómez S. , Pineda-Muñoz A. , González-Guevara J. A.
Published: December 2007

In this paper experimental results obtained for the oil displacement by water within a two-dimensional vuggy fractured porous cell are presented. The experiments were carried out with an acrylic cell, where fractures were represented by channels of 1.6 mm wide, 1.2 mm deep and 19 cm long, whereas the vugs were represented by cylinders of 1 cm diameter and 1.2 mm deep.

The experimental procedure is as follows: the cell, saturated 100% with oil was placed horizontally and at time t=0 water was injected at a constant rate. Photographs were taken to follow the water front in the cell; then, the area corresponding to oil and water was measured. In this way the water saturation in the cell was determined. This water saturation is equal to the oil recovery, considering oil and water as incompressible fluids.

Based on the experimental results, a theoretical model was developed. This model considers that the porous space is constituted by two regions: one that can conduct fluids, called flow region and a stagnant region that interchange matter with the flow region through a diffusion-like process. Analytical solutions for water saturation and normalized oil recovery are presented.

The model fitted in a reasonable way the experimental data of normalized oil recovery, indicating that the theoretical model can be a useful tool to explain oil recovery processes in vuggy fractured reservoirs.
Stochastic Modeling of Rock Heterogeneities Applying New Autocorrelation Estimators and Simulated Annealing
Authors: Saccomano A. F. , Savioli G. B. , Bidner M. S.
Published: December 2007

Two new integral estimators of spatial autocorrelation are put forward and studied. The first is LV (Local Variance), based on the variance of the distribution. It is also an estimator of the average value of the semivariogram within a region. The second, SLV (Semivariogram from the Local Variance), is related to the derivatives of the former. It is an estimator of the semivariogram itself. The behavior of these two estimators is compared to that of the classical semivariogram estimator (CSV) using different data sets. SLV behavior is similar to that of CSV. Both are noisy and present fluctuations that increase with lag distance. Instead, LV is smoother and more resistant to outliers, making it easier to be represented by a theoretical model. Also, LV is less affected by individual values of samples, honoring the general statistics of data.

Afterwards, the ability of the three estimators to model actual spatial variability is tested using the Simulated Annealing optimization technique. This technique has a good performance when any of the three estimators is included in the objective function. It is able to reproduce actual porosity or permeability fields, even when there is a specific spatial structure (such as cyclic, staircase-like, etc). However, LV has a main advantage: it still preserves the main features of the spatial structure even though it is very smooth.
Two Procedures for Stochastic Simulation of Vuggy Formations
Authors: Casar-González Ricardo , Suro-Pérez Vinicio
Published: December 2007

Simulated annealing and stochastic simulation based on indicator kriging are used to describe vuggy formations in a Mexican offshore field. Besides heterogeneity associated to these carbonated formations, vug spatial distribution is an important issue since hydrocarbon storage and deliverability to the wells is highly controlled by vugs density and connectivity. From computed tomography images, exhaustive 3D statistics are derived to build 3D stochastic models of those vuggy formations. Multiple point statistics simulated annealing and sequential indicator simulation based on kriging are used to model vugs geometry. The results indicate that both approaches honor the target statistics, and visual inspection of such images confirm good reproduction of connectivity. Further, it is shown that computer performances are different with simulated annealing being the most demanding. Although stochastic images from indicator kriging can be used as initial images for simulated annealing, it is demonstrated that few value is added by imposing multipoint statistics in the framework of vugs modeling. Therefore, it seems that stochastic simulation based on indicator kriging can build, with an acceptable computer cost and good reproduction, 3D images of vuggy formations.
Heavy Oil Solution Gas Drive in the Venezuelan Orinoco Belt: Laboratory Experiments and Field Simulation
Authors: Andarcia L. , Kamp A. M. , Vaca P.
Published: December 2007

The Venezuelan Orinoco Belt heavy oil reservoirs have been subject to research over recent years with respect to their possible anomalous production behavior. High recovery factors and high initial production rates are expected, which is not predicted using conventional characterization and simulation practices. Heavy Oil reservoirs with this behavior are referred to as foamy oil reservoirs.

We present laboratory experiments that can be used to obtain predictions on the production behavior of foamy oil reservoirs. These experiments were used to obtain relative permeability end-points. The effect of confinement pressure is shown, as depletion completed with an overburden stress shows a much higher recovery and critical gas saturation than the depletion without stress.

Preliminary reservoir simulations have been carried out for an area of the Orinoco belt with 7-8 years of production history, using the obtained relative permeability end-points. The match of the oil production rate and gas/oil ratio curves is presented. It is shown that an increase of gas-oil ratio (GOR) in the field could not be predicted with the laboratory-derived relative permeability end-points. This discrepancy may be the result of too coarse a simulation grid in the region of the well bore or may just highlight the difficulty in scaling laboratory measurements to the field-scale. The implications for field-scale simulation have not been fully explored.
Computer Simulation of Formation Damage Resulting From Thermal Recovery
Authors: Moore C. H.
Published: December 2007

The thermal recovery of heavy oil and bitumen from cool reservoirs via the injection of steam and hot fluids results in geochemical systems that are far from equilibrium. As a result, mineral and other solid grains in the reservoir may react with the injected fluid. These reactions often result in the dissolution of preexisting minerals and the formation of new ones. The types of minerals that form and their distribution in the reservoir may significantly impact reservoir quality, even to the point of blocking production.

If such deleterious phenomena occur, they can be irreversible. Consequently, it is prudent, when exploiting reservoirs with certain types of lithologies, to try and predict whether or not such formation damage is likely to occur. Computer simulations are the main tool for making such predictions.

This paper is intended to acquaint the reader with the basic type of analysis that can be done using a coupled flow/reaction geochemical computer code such as REACTRAN. Two basic reservoir types are used as examples, a carbonate reservoir and an immature sandstone reservoir. Two somewhat different lithologies for each reservoir type are used in the examples.

The examples show that different kinds of formation damage may take place. These include porosity gain that may lead to collapse, the formation of mineral fines from precipitation that may lead to fines migration problems, and the formation of clays and clay-like minerals that may occlude permeability.
Evaluation of IOR Methods for the Boscán Field
Authors: Kumar Mridul , Sahni Akshay , Alvarez J. M. , Heny C. , Vaca P. , Hoadley S. F. , Portillo M.
Published: December 2007

Chevron and Pdvsa-Intevep jointly conducted an evaluation of improved oil recovery (IOR) opportunities for the Boscán field to increase oil recovery and to help maintain future production rate. The shallower, northern area of the field was the target of this evaluation. Based on process screening results of Phase I, steam injection, waterflooding, and diluent/solvent injection were selected for a more detailed evaluation in Phase II.

During Phase II, fine-grid, geological models were built for the northern part of the field. In addition, laboratory experiments were conducted to obtain necessary data. The geologic model and input data were first validated using primary production data from representative wells. Numerical simulation studies for steam injection and waterflooding were conducted on three different segments to capture geologic variability. Effects of operating conditions and important uncertainties of input parameters on production forecast were obtained.

Results show that IOR processes have significant upside oil recovery potential. However, considerably smaller well spacing (well spacing of 290-m or pattern spacing of 54-acre or less) will be needed for floods. Only cyclic process can work at current spacing. Steamflooding results in the highest recovery (up to 43% OOIP). Cyclic steaming provides opportunity for accelerated recovery prior to steamflooding. Laboratory diluent injection appears promising but needs further evaluation.
New Thermal Recovery Technology and Technology Transfer for Successful Heavy Oil Development
Authors: Greaser Gary R. , Ortiz J. Raul
Published: December 2007

Continuous development and rapid deployment of new thermal technologies are critically important in the quest to make heavy oil projects cost competitive. Worldwide heavy oil deposits are abundant, but conventional development schemes may not be financially competitive. Currently, oil companies have a multitude of new investment opportunities, which further stresses required funds available for the continued development of new and existing heavy oil assets. How can heavy oil assets compete financially? New, cost effective technologies must be developed and deployed to improve the margins of heavy oil assets. An effective partnership must be maintained between the technology developers and the technology users to ensure a smooth transition from concept to field test to commercial application. The alignment of technology development to the real business needs is essential. This paper reviews a portfolio of new heavy oil technologies that Texaco is pursuing alone and in partnership with other companies. The processes used to assure business alignment, technology transfer, and deployment are also discussed. The heavy oil and thermal technology development portfolio includes novel steam generation, improved steam delivery (measurement and distribution), and aggressive heat management projects. These new surface and sub-surface heavy oil technologies will be discussed relative to the potential impact that they could have on several existing and new heavy oil fields.
Recovery of Heavy Matrix Oil by Capillary Imbibition in Naturally Fractured Reservoirs
Authors: Babadagli Tayfun
Published: December 2007

If matrix is water wet and enough amount of water is supplied in fractures, capillary imbibition becomes the governing recovery mechanism in naturally fractured reservoirs. When the matrix contains heavy oil, however, this process becomes highly ineffective due to slow recovery rate and high residual oil saturation. Additional methods, other than waterflooding, such as injection of surfactant solution, polymer solution or hot water should be considered to increase the effectiveness of the capillary imbibition recovery of heavy matrix oil.

This paper includes the results and analysis of the laboratory scale experimentation of these three methods. Experiments are conducted on Berea Sandstones (water-wet sample) using heavy oil samples with the viscosities ranging between 185 and 630 cP. Carbonate cores (oil-wet limestone samples) were also used with light oil samples for comparison purpose. Different boundary conditions are created using epoxy coating. Based on boundary conditions, co- or counter-current type capillary imbibition takes place. Performances of the three methods are compared in terms of ultimate recovery and recovery rate. It is observed that all three methods yield higher and faster capillary imbibition recovery compared to waterflooding. The contribution of chemical additives and high temperature of water becomes more pronounced as the viscosity of oil increases. This contribution is more prominent on ultimate recovery than the recovery rate, especially for chemical solution cases.
Two-fluid Mixing Enhancement by Using a Static Turbulence Generator
Authors: Ortega P. , McGrath G. , Rojas L.
Published: December 2007

The numerical simulation of a static T-type mixer for turbulent mixing of miscible liquids is reported. The simulation was carried out using CFX, a commercial computational fluid dynamic simulator. The effect of mixing intensification caused by turbulence generators placed downstream of the injection point of the Tee was evaluated in terms of reduction in mixing length for a given mixture quality, uniformity of turbulence intensity and efficiency of energy conversion to useful mixing energy.

The mixing quality for an intensified and conventional T-type mixer was compared, and the turbulence generator geometry was optimized. Main stream Reynolds numbers between 50000 and 100000 were considered for additive volume ratios in the range 0.1 – 10%. Selected simulations were validated with experimental data available in the literature for conventional smooth T-type mixers (no ribs).

Results were in good agreement with experimental correlations available at high Reynolds numbers.

Simulations demonstrated that mixing enhancement was efficient with turbulence generators, extending the Reynolds number range for which compact, low pressure-drop devices may be used for intense mixing. The optimum geometry for turbulence generators was evaluated using criteria based on energetic and spatial efficiency and in all cases the simple Tee was used as the point of reference.

Finally, practical design correlations are presented to enable the mixing quality of two miscible streams to be estimated for a simple Tee with and without additional turbulence generators over a range of Reynolds numbers and injection conditions.
Optimal Exploitation Scheme in MFB-5 Reservoir
Authors: Blanco M. , Rodríguez T. , Crespo J. , Granado A. , de Rojas B.
Published: December 2007

In order to contribute with the development of Orinoco Belt reservoirs, a simulation model was created to be used on the extra heavy crude oil reservoir MFB-5, located in Bare block, Hamaca area. So far, this reservoir has produced about 1% of oil in place, estimated in 216 MMSTB. Besides, it has an associated aquifer, which generates high water cuts caused by channeling. This situation motivate the study of different exploitation strategies to obtain the most profitable oil recovery. At present reservoir conditions and under primary recovery, there is still a 14% of total recoverable oil (28 MMSTB). The main objective of this work was to obtain the highest oil recovery with the lowest number of new locations, and with the most favorable well production conditions for this reservoir. An economical analysis was performed for each scheme and the result was that the best technical and income-producing exploitation strategy, would recover 15% of OOIP in 20 years, which would exceed recoverable oil in place in 6% if the current 9 active wells are maintained producing under the present strategy.
Fracturing with Crosslinked Methanol in Water-Sensitive Formations
Authors: Malone Mark R.
Published: December 2007

The use of methanol in fracturing is not new technology. Its origin and application in hydraulic fracturing can be traced back to the 1960's. However, advances in fracturing fluid chemistry and breaker technology have improved dramatically creating new systems such as crosslinked methanol, the subject of this paper. Methanol has been utilized in the well stimulation industry for many years to take advantage of its low surface tension properties and miscibility with various formation fluids. This paper will discuss advances in crosslinked methanol system technology, system compatabilities, field application and practical safety precautions. The fluid system rheological properties and proper breaker application will be discussed as well.

In recent years, the industry has become more aware of the challenges associated with formations recognized as "water sensitive". These issues can be associated with mobile and swelling clays, or undersaturation of the formation, otherwise known as aqueous phase trapping. The paper will discuss these issues as they pertain to proper fluid selection and more specifically, the selection of crosslinked methanol as a fracturing fluid.

Formation properties of zones treated with crosslinked methanol will be presented as well as post fracture treatment results.
Changes in the Performance of Texas Gas Wells
Authors: Swindell Gary S.
Published: December 2007

Much recent attention has been recently given to depletion of U.S. natural gas reserves, particularly since many forecasts predict a 30 TCF annual gas market. A comprehensive look at the way initial production, decline rates, and reserves have changed over the last 30 years in Texas, the source of 1/3 of the country’s natural gas, leads to concern about whether current drilling activity will be able to maintain the current supply, much less increase gas production 1.

The decline rates in new Texas gas wells have changed from about 20% in the first year for wells drilled in the 1970’s and 1980’s, to more than 55% for wells drilled in 1998 and 1999. At the same time, the contribution to the state’s supply from new wells has sharply increased from 8% of the state’s supply to more than 15%. Although the initial production rates from an average well have actually improved from a low of 15 MMCF per month in the early 1980’s, to 44 MMCF per month in 1999 due to improved completion technology and horizontal drilling, the combined effects of fewer completions and high decline rates suggests that a decrease in Texas’ production capacity may occur in the near future. Drilling above the current activity will be necessary to sustain the state’s gas production.

Normalized rate vs. time curves were developed for each year since 1970 to obtain initial rates and decline profiles. The curves were extrapolated to an estimated ultimate recovery, changing from 6 BCF per well in the early 1970’s to 1 BCF per well in the late 1990’s.
New Approach to CO2 Flood: Soak Alternating Gas
Authors: Murray Malcolm D. , Frailey Scott M. , Lawal Akanni S.
Published: December 2007

To date, field wide CO2 flooding is continuous or WAG injection processes. In individual wells a huff’n’puff scheme has been used where CO2 is injected into a well followed by a shut-in period; after a predetermined time, the well is produced. Each of these methods have practical, technical, and economical limitations. This paper describes a new CO2 injection method that combines all three of these methods but excludes water injection.

Continuous CO2 may be optimal in reservoirs that are not conducive to water injection and do not have CO2 mobility control problems such as early breakthrough. However, continuous CO2 requires a large initial CO2 volume that may be unavailable and relatively expensive. WAG is very common with variations of different ratios of water to CO2 volumes and tapered ratios. WAG reduces mobility problems and thereby improves areal sweep efficiency; CO2 purchase expenses may be lower due to the requirement of lower CO2 volumes. Unfortunately, water injectivity following CO2 injection may decrease, and the water increases lift and water handling expenses. Huff’n’puff is effective similar to a near wellbore stimulation, but may not realize the benefits of a full field injection program. Also, this adds the complication of injection and production capabilities required in the same well. This may be impossible for some wells on artificial lift.

The proposed method is to inject CO2 and shut in the well similar to the huff and puff, but instead of producing the well inject CO2 again. This process is a cyclic process like WAG, and shares the variables of the duration and volume of CO2 injection and the duration of the shut-in period. This method eliminates injectivity and production expenses associated with water. Mobility is controlled by near wellbore achievement of miscibility by the increase in mass transfer between the CO2 and oil during the shut-in portion of the cycle; i.e. a smaller portion of the reservoir has relatively low viscosity, injected CO2 due to miscibility between oil and gas occurring nearer the injection well.