bluuebunny/crossref_metadata_2025 huggingface dataset:
Relative Permeability Modifiers: Myth or Reality?
Authors: Botermans C. Wouter , van Batenburg Diederik W. , Bruining Johannes
Published: December 2007

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

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

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

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

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

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

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

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.
Application of Seismic Attribute Filtering with Factorial Kriging to Estimate Porous Volume: A Case Study on a Brazilian East Coast Offshore Turbidite Reservoir
Authors: Mundim Evaldo Cesário , Remacre Armando Z.
Published: December 2007

The estimation of reservoir properties is a risky issue. Uncertainties come around; the number of wells (hard data) is often low and poorly distributed. Densely sampled, 3D seismic information (soft information) has been seen as a key to reducing interwell uncertainties. As it is well known, however, even after seismic processing, noises and sign distortions remain if not introduced by the processing itself. Moreover, inconsistency in horizons picking, during interpretation, worsens the quality of the obtained attributes with corresponding impact for its use as a predictive variable for reservoir mean properties estimation.

In this paper, we discuss incorporation of seismic attributes filtered by Factorial Kriging via conditional simulation on reservoir porous volume estimation. The seismic attribute mean acoustic impedance obtained from a 3D seismic program with seismic stratigraphic inversion is considered. It shows itself to be well correlated to the porous thickness of the reservoir interval under consideration. A nested corregionalized model, which presented two structures, was fitted to the attribute. The small range associated to data noises was filtered by Factorial Kriging, which improved the correlation between the acoustic impedance and the porous thickness. The dispersion of the conditional simulation constrained by the filtered seismic attribute is lower than the dispersion of the conditional simulation constrained by the pre-filtering attribute, reducing the uncertainty of the reservoir porous volume estimation.
Lateral Discrimination of Sand Packets with 3D-Seismic-Derived Acoustic Impedances, La Itala, Golfo San Jorge, Argentina
Authors: Merletti Germán , Marcos Victoria , Courtade Sergio F. , Pringgadani Meilando
Published: December 2007

The depositional environment in the west section of the Golfo San Jorge Basin is characterized by fluvial sand-shale sequences in which the reservoirs rarely have thickness that exceeds 10m, while average thickness is 4m. The acquired seismic has a tuning thickness of 17m, so that the wavelet effect and thin bed interferences make the seismic derived attribute analysis not ideal for lateral and vertical delineation of sandstone complexes. The seismic limitations of only describing interfaces without discriminating lithologies, is overcome inverting 3D seismic traces into pseudo logs of Acoustic Impedances by applying a constraint sparse spike algorithm. Both well data (lithology and compaction) and horizons (structural framework) help to constrain the process, thus the reflectivity series found meets the criteria of minimizing the residual between the synthetic model and the real 3D seismic trace. An Acoustic Impedance volume is derived from the reflectivity series, (the frequency spectrum is limited to the seismic bandwith lacking the low frequencies corresponding to compaction) and is called bandlimited. Impedance logs from key wells were generated, filtered to a range between 0-7 Hz and then interpolated (honoring both the stratigraphy and the structural framework) to generate a low frequency model of impedances. By merging the low frequency model with the bandlimited volume a total Acoustic impedance volume is obtained.

Well data analysis describes that Acoustic impedances not only at well frequency but also at seismic frequency are visualized as maximum for sandstone packets. The acoustic impedances derived from the inversion process are sensitive to the presence of a stack of several sand units and hence can be used to map lateral variations of petrophysical reservoir properties. We have attempted to quantify the petrophysical properties of such sand sequences using extensive well control. To do so we first low-pass filtered the well logs to exhibit vertical variations consistent with those of the 3-D seismic data. The low-pass filtered logs were further analyzed via lithology-based cross-plots to ascertain their effective petrophysical properties. This procedure successfully provided us a quantitative model to predict vertical and lateral variations of petrophysical properties from seismic-derived acoustic impedances. We have also developed a similar procedure based on attributes extracted from the reflectivity data generated as by-product of the inversion process. This effectively allowed us to delineate the lateral and vertical petrophysical behavior of useful sand units for subsequent in-fill and step-out development operations. We have successfully tested this methodology on a number of new wells in the area.
Optimizing Development Costs by Applying a Monobore Well Design
Authors: García Rodolfo , Alfaro Edgardo , Bernardis Alfredo , Casalis Daniel , Gallardo José , Del Zotto Daniel , Alonso Adrián
Published: December 2007

The An Aike-Barda Las Vegas field, located in the Austral basin 80 km west of Rio Gallegos, Argentina, represents an important discovery in basin development in recent years. The field is an important Springhill formation gas reservoir at an approximate depth of 3100 m and with static pressure of 4400 psi. Gas rates are up to 1 MM m3/d/well.

Drilling appraisal and development wells requires the optimization of every operation involved. In this context, improvements in well construction and completion methodology are important contributions. Original well design included 13 ⅜-in. surface and 9 ⅝-in. and 7-in. casings, with a permanent packer and 4 ½-in. tubing. The new monobore well design reduces the diameter of each drilled section, narrowing to a 4 ½-in. monobore installation through the pay zone. The rigless completion includes coiled tubing.

Before adopting the design change, potential risk analyses were made to account for the possibility of future reentries and for simultaneous development of a second target (Magallanes formation) at 1700 m. The final well design model showed a cost savings of 30 percent, a sizeable impact on the economics of this project.
Modeling Aspects of Wellbore Stability in Shales
Authors: Frydman M. , da Fontoura S. A. B.
Published: December 2007

Drilling problems associated with wellbore instability are normally aggravated when crossing shale layers. Instabilities in shales may be caused by a complex mechanism of shale-drilling fluid interaction and by the overstress of the rock formation. Wellbore stability models that include some aspects of this coupled phenomenon have already been developed. However, the use of these models without the knowledge of the associated simplifications may lead to wrong conclusions.

The present paper discusses the modeling aspects of the coupled process. Three formulations are compared: an analytical elastic solution without the diffusion process, an analytical poroelastic solution and a numerical chemical-hydro-mechanical model. The objective is to analyze the applicability of each model.
Design of an Acid Stimulation System With Chlorine Dioxide for the Treatment of Water-Injection Wells
Authors: Cavallaro A. , Curci E. , Galliano G. , Vicente M. , Crosta D. , Leanza H.
Published: December 2007

Water treatment and injection well stimulation are two important contributions to oil lifting cost at Barrancas oil field. As most of mature fields, waterfloding represents a hugh amount of oil production. Although average water quality is quite good some injection wells require regular hydrochloric acid stimulation in order to restore injectivity, impaired by different solids, mainly calcium carbonate and sulfides. A new stimulation system was designed. The system combines the conventional acid system with an aqueous chlorine dioxide solution.In this approach chlorine dioxide activates at the bottom of the injection well. The oxidating power of chlorine dioxide removes completely all solids that are not sensitive to acid treatments. The synergistic effect of the proposed treatment was determined in two different flow core tests on reservoir samples.Due to successful results at the lab, a decision was made to perform field tests in four injection wells. A dramatic and continuous decrease in wellhead pressure were the results obtained after several weeks of treatment. In order to analyze and prevent corrosion effects a parallel study was designed and conducted on tubing samples at reservoir conditions.
Water Control Experiences in the Motatan Field Using Specially Designed Gels
Authors: Alvarez Inés , Espinoza Mária G. , Amaury Marín T. , Hernández María I. , Rossana Caira , Der Sarkissian Juan , Martínez José L.
Published: December 2007

Motatan field is located in the Western part of Venezuela. The area has two main lenticular reservoirs which are constituted by low primary permeability sandstone, in most of the cases with a high density of natural microfractures. The Domo Sur area presents high water cut problems, which have been attributed to natural fractures channeling. Therefore, gel technology evaluation was proposed to mitigate this problem. Four wells were selected. The injected gel system was designed to be used at specific reservoir conditions and with Disproportionate Permeability Reduction (DPR) effect. In all cases, the gelant was injected using the bullheading technique and a penetration ratio of about 15-17 feet was used. Overall results showed the system effectiveness, since it reduced water production in all wells. A reduction of 6,900 BWPD (80.4%) was obtained and oil production was increased in 700 BOPD (31.7%), once the water cut was stabilized.
Improvement of Gas Recovery Factor Through the Application of Dewatering Methodology in the Huamampampa Sands of the Aguaragüe Field
Authors: Girardi F. , Lagrenade E. , Mendoza E. , Marín H. , Conti J. J.
Published: December 2007

The Huamampampa formation is one of the best gas reservoirs of Devonian basin located in the North-West of Argentina. In the Aguaragüe field, this natural highly fractured reservoir has produced a large amount of gas, even after most of the producing wells became watered-out.

An excellent improvement of gas recovery factor has been achieved by the implementation of an unusual dewatering methodology. The method consists of applying a gas-lift production system to extract water from each flooded well. This type of exploitation causes a delay of the wells water encroachment and an increment of matrix gas production through the wells located at the top of the structure.

In this paper we show the benefits of the implementation of this gas exploitation scheme as applied to the field.

There have been numerical simulation studies performed in different stages of the exploitation and by different authors. The last study takes into account a vast gas and water production history. Different exploitation cases have been analyzed. The sensitivity scenarios presented here demonstrate the need and the benefits of dewatering.
Analysis of Salinity Changes Caused by Brief Shut-in of Wells in Secondary Oil Recovery
Authors: Somaruga C. A. , Gazzera C. E. , Wouterlood C. J.
Published: December 2007

This paper presents a methodology to determine the origin and dynamics of bottomwater in a producing well influenced by several injectors in a secondary recovery pattern. This methodology requires a brief shut-in period in order to better identify the effect of flow patterns in the near wellbore region of the producer. During the shut-in period, water coming from the dominant injection wells can move forward, invading areas of a layer that has been previously occupied by other waters. Once the well is reopened, a salinity contrast between the injection and produced waters can be measured.

Then, it is proposed to determine the original flow distribution around the producing well by means of a simple balance of salt mass.

Salinity changes produced by shut-in injectors are analyzed as a complementary tool for identification of dominant injectors.

Representative results of several cases that may arise from a hypotetical reservoir are also presented. Finally, a case study from the Neuquen Basin of Argentina is presented that demonstrates the proposed methodology.
Numerical Simulation Model of Highly Faulted Reservoir based on an Integrated Approach in Lake Maracaibo
Authors: Mijares O. , Ramonez M. , Romero M. , Muñoz P.
Published: December 2007

This paper presents the results of the numerical simulation model of the highly faulted reservoir C40/44 located in the West Flank, Block I, Lake Maracaibo western Venezuela. Based on an Integrated Approach study1, the 3D dynamic model allowed to evaluate the impact of the sealing character of the inverse faults and their potential influences in the migration and fluid distribution across the faults, and consequently, the grade of difficulty in the adjustment of the historical production subjected to the water injection influence from Dic/71.

In spite of the simulation model is highly sensitive to the changes of the reservoir parameters, it is considered that the feasibility grade of the model is enough (85%), to understand the relative movement of the fluids for blocks, to quantify with certainty the recurrent remaining reserves and to identify the field development opportunities and exploitation.
Increasing Reserves by Applying 3d Seismic in Mature Exploitation Areas
Authors: Anzulovich L. , Cerdán J. , Regazzoni C. , Lay R.
Published: December 2007

This paper describes the positive results yielded by a 3 D seismic survey conducted across mature exploitation areas of the La Ventana and Vizcacheras oil fields.

It shows how to carry out integrated field scale studies and discusses the La Ventana Norte and Cañada Dura discoveries made by applying a new structural model derived from said 3 D seismic survey. The discoveries pertain to structurally low areas that had been disregarded before recording the 3-D survey.

The original exploitation area has been substantially extended with the discovery of new separate areas.

Multidisciplinary studies based on 3 D surveys allowed to carry out deep studies on mature oil fields. They also contributed to define fundamental criteria for understanding lithologic and stratigraphic changes, which helped distinguish this type of fields.
Transport Properties of Porous Media from Thin-Sections
Authors: Hidajat I. , Rastogi A. , Singh M. , Mohanty K. K.
Published: December 2007

The objective of this work is to predict transport properties within any complex porous medium from its 2D micro-image. Three-dimensional porous media are generated that have the same porosity, autocorrelation, chord length distribution and lineal path function as a given 2D micro-image of a medium. The properties of the regenerated media are compared with those of the original media. A pore skeleton and Euclidean distance map are determined for the 3D pore-space from which body radius, throat radius and connectivity distributions are extracted. This network structure is used in calculation of transport properties. Specific surface area is estimated accurately. Permeability and formation factor are estimated approximately. The correlations between adjacent pore bodies and throats are identified.
Stratigraphy, Sedimentology, and Reservoir Characteristics of the Lower Member of the Yacimiento El Trébol Formation
Authors: Courtade S. F. , Arijon E. , Salomone G. , Chebli P.
Published: December 2007

Exploration in the offshore Golfo San Jorge Basin requires an understanding of the regional trends of the Lower Yacimiento El Trébol Fm. Sandstones. These reservoir rocks yield the best oil shows in the offshore and they are among the most prospective and prolific onshore reservoir on the Golfo San Jorge Basin's north flank.

Detailed correlation enabled identification of three lower order sequences in this stratigraphic interval. These sequences are recognizable on seismic sections and well logs.

The Lower Yacimiento El Trébol interval was regionally correlated from the offshore wells to the producing intervals at Escalante and El Trébol fields. No major truncations or stratigraphic wedges were identified on seismic lines or well logs, although the individual sequences that comprise this package can thin against some persistent structural highs.

In addition, these sequences were correlated in 144 wells all around the north flank of the basin; sand thickness was measured from the SP curve in these wells. Net sand and sand percent maps were created.

These maps demonstrate that lower Yacimiento El Trébol sandstones are concentrated in sand fairways in the Comodoro Rivadavia area and in the area south of the Marta wells. Conversely, there are many parts of the basin where Lower Yacimiento El Trébol Formation is represented by silts and shales (west and south of Comodoro Rivadavia and between Comodoro Rivadavia and Marta wells).

Sand rich fairways, represented by gross thickness isopachs, map as trends that are perpendicular to the basin edges. Lower Yacimiento El Trébol production is found in these thick sand areas, while in thin sand areas, production comes from the underlying Comodoro Rivadavia Fm.
GIS of Surface Facilities
Authors: Pochettino H. F. , Kovacs G.
Published: December 2007

In all commercial activity, in order to increase the business objective, that is the rentability, the corresponding Administrations work for the maximization of the investments efficiencies.

Each increase in the celerity and precision of the information feed-back process will become in an increase of the benefits because the deviations from the budget and the corresponding actions will be the smallest.

In the Oil Industry an index commonly used, that include the costs started in the different stages of the production process, is the Operative Cost.

Because Surface Facilities are part of the Production System, theirs costs will increase the Operative Cost.

One form to optimize the Surface Facilities cost is by the automation of the Surface Facility's Information Systems so as to reduce answer times. Computing is one tool to find this automation.

GIS is a computing tool developed for integrate information and bases its work in the administration of the information related to points placed over the Earth surface.

The present job shows the GIS Project developed for the Vizcacheras Field Surface Facilities, Province of Mendoza, Argentine Republic.
Steam-Propane Injection for Production Enhancement of Heavy Morichal Oil
Authors: Ferguson M. A. , Mamora D. D. , Goite J. G.
Published: December 2007

Laboratory experiments have been conducted to investigate the use of propane as a steam additive to enhance production of 13.5°API oil from Morichal field, Venezuela. The main component of the apparatus is an injection cell into which is tamped a sand mix consisting of sand, water, and oil. Thermocouples placed in the cell enable tracking of the steam front. The cell pressure is set at 50 psig, while superheated steam at 160°C is injected at 5 ml/min cold-water equivalent at the top of the cell. Produced liquid is collected from the bottom of the cell, and after emulsion-breaking treatment, oil and water volumes are measured.

Experimental runs have been conducted in which the propane:steam mass ratio is varied from 0:100 (steam only) to 5:100. A run using 5:100 nitrogen:steam mass ratio has also been made to evaluate the contribution of convective heat to oil production. The main findings of this research (derived from four runs with consistent operating conditions) are as follows. First, the propane:steam mass ratio of 5:100 accelerates the start and peak of oil production by 20 % and 13 % pore volume steam injected (cold-water equivalent), compared to steam injection alone. In the field, this could translate into significant gain in discounted revenue and reduction in steam injection costs. Second, oil recoveries appear to be similar in all cases, 63 % - 70 % OOIP. Third, the start of production is practically the same for 0:100 and 1:100 propane:steam ratio and for 5:100 nitrogen:steam ratio, indicating probably a minimum propane:steam ratio requirement. Fourth, oil production acceleration in the 5:100 propane:steam case is probably caused by 'dry distillation'. Last, convective heat transfer at any of these low (5:100) ratios appears to be of secondary importance. Research continues to better understand the mechanism and thereafter model the production of oil under steam-propane injection.
Reservoir Characterization and Exploitation Scheme in the Orinoco Oil Belt
Authors: Uzcategui E.
Published: December 2007

Production development in the Orinoco Oil Belt started with data gathering programs that included high resolution 3D. Although the acquired seismic information was considered of good to very good quality, it was not enough to provide the details needed to maximize the amount of sand contacted through horizontal drilling.

The complexity of the reservoir architecture required additional control data to allow the operator to position the well in targets suitable to support the economic of the project. Additional drilling, in the form of stratigraphical (vertical and/or slanted) and observation wells, plus coring programs, well seismic and rock sampling provided the input for an appropriate reservoir description.

Once model integrating such data were produced, geostatistical manipulation allowed the estimate of ranges of oil in place, sand body typing, aquifer distribution and so forth. This effort clearly impacted the development programs by suggesting changes to multilateral geometry, pad configuration, draining point location and well spacing.

This paper will focus on how should the above mentioned topics to optimize the field performance be linked and still achieve the economic goals for everyone defined in the projects.
Controllability and Observability Issues for SAGD Intelligent Control in Venezuela
Authors: Herrera Lourdes , Mendoza Humberto
Published: December 2007

PDVSA has being operating a Steam Assisted Gravity Drainage (SAGD) process[I1] since 1997, as part of a pilot test carried out in the T a Juana Field, Western Venezuela.

This paper focuses on issues concerning the first step to obtain controllability and observability of the SAGD process taking into account heat distribution, heat management and evolution of steam chamber, at each time, for an efficient reservoir drainage.

Main issues concerning observability are pursued with the installation of subsurface sensors such as discrete pressure and temperature, as well as a fiber optic distributed temperature system. Experiences in PDVSA show that a little portion of the steam chamber can be observed and extrapolated to emerging analytical or numerical related models. In the other hand, issues concerning controllability can be inferred from observing patterns derived from process behavior, coming from direct measurements at bottomhole or from well testing analysis at surface.

General discussion on controllability and observability will be addressed giving particular ideas over experiences in PDVSA, exploring other ways to attack these two issues as for example using microseismic downhole sensors for steam chamber development and incorporating artificial intelligence in control algorithms to manage the process.
Coupled Hydro-Geomechanical Modelling of the Cold Production Process
Authors: Coombe Dennis , Tremblay Bernard , Tran David , Ma Huiping
Published: December 2007

Aspects of the cold production process have been studied mechanistically employing a unified framework and coupled geomechanical-fluid flow simulation models. The unified framework is a generalization of that proposed by Papamichos et al1 such that stress concentration causes mechanical weakening, and fluid flow causes erosional mobilization of sand particles. Porosity change is the primary coupling parameter whereby the soil mechanical and strength properties are altered as a continuum damage process, while erosional generation of mobilized sand particles causes fluid porosity increase and oil-sand slurry flow.

These ideas are implemented in coupled simulation models using different coupling strategies and different physical assumptions to study various aspects of the cold production process. The first coupled model is a stand-alone finite element model for two-dimensional radial plane strain and single phase fluid flow. Here the geomechanics and fluid flow aspects are fully coupled such that the time dependent (undrained to drained) mechanical stress transfer is strictly preserved. The second coupled model allows a more complete fluid model (including gas ex-solution and water influx), as well as a time dependent sand mobilization mechanism, but at the expense of a weaker (time explicit) geomechanical-fluid flow coupling, through Settari's concept of volume (effective porosity) coupling21.

These models are applied to simulations of cold production at the laboratory and field scale. The laboratory scale models are based on the CT experiments of Tremblay et al2, which emphasize the erosional aspects of the cold production process, and its coupling to gas exsolution. The field scale models are based on single well production observations in Alberta bitumen reservoirs, such as Yeung et al44 and include sensitivities to water influx. Additional geomechanical aspects which may be important in deeper reservoirs such as those in Venezuela are also illustrated.

Finally implications and recommendations for future simulation modelling at the field scale are provided.
Experimental Investigation of Foamy Oil Solution Gas Drive
Authors: Kamp A. M. , Heny C. , Andarcia L. , Lago M. , Rodriguez A.
Published: December 2007

A five-year laboratory and simulation investigation on heavy-oil solution-gas drive processes is reported. It is shown how the interpretation of these processes has changed over the years. Initially, it was attempted to take into account the "bubbly" character of the oil by changing the oil thermodynamical properties. Non-conventional PVT properties accounted for supersaturation and trapped gas bubbles. Later, in agreement with work in other research groups, the low produced gas-oil ratio and high recovery factors were modeled by introducing low gas-oil relative permeability. This allowed for history matching of laboratory and field data, but doubts remain about the predictive capacity of reservoir simulation models. This doubt is motivated by the observed flow geometry of the (dispersed flow), which is not physically taken into account in the reservoir simulation equations. It is concluded that more work is necessary on the determination of the mechanisms that govern the flow, and on the development ofm odels that more correctly represent the physics of dispersed gas-liquid flow in porous media. Further experiments in cores and micromodels, together with microscopic modeling of flow in pore spaces, should be part this work.
Device for Testing the Dynamic Stability of Highly Concentrated Emulsions against Coalescence
Authors: Ortega P. , McGrath G. , Núñez G. , Joseph D.
Published: December 2007

A portable and compact device with independently controlled shear, pressure variations and residence time for testing changes in the drop size distribution of concentrated oil in water emulsions is described by Joseph et al (1999, US Patent 5,987,969). Examples are presented where the device is used for quality control of emulsions in transport and manufacturing operations.
The Orinoco Oil Belt Targets Light/Medium Crude Oil and Product Market Opportunities
Authors: Alvarez C. E. , Marciano C. , Pereira C. , Larrauri K. , Morros F. , Bauduhin P.
Published: December 2007

The Orinoco Oil Belt keeps a firm path towards the manufacturing of upgraded crude oils. Currently, all efforts are concentrated on the production of its first barrel of synthetic crude oil from the first of the four environmental friendly world class projects in progress (named Petrozuata, Cerro Negro, Sincor and Hamaca) in the Jose area, located on the northeastern side of the country. Its huge reserves support at least ten additional new projects, each processing some 200 MBCD for a 35-year period to manufacture L/M crude oils and high quality products in Venezuela. These potential new projects would represent an outstanding impulse to the economic development of the eastern part of the country. Several options to integrate production activities, upgrading plant schemes and locations, as well as market opportunities have been studied. Options contributing with the highest added value to the nation and project partners are highlighted in this paper. The "tailor made" upgrading schemes to process extra heavy crude oils contribute to strengthen the quality of the Venezuelan hydrocarbon exports package, and furthermore, maximize its value. A new project to transform extra heavy crude oil from the Orinoco Oil Belt could also support commercial efforts to penetrate new markets as well as contribute to the development of the national chemical industry through the industrialization of off gases and solids produced in its upgrading plant. The study results confirm the Orinoco Oil Belt as PDVSA secure source of light, medium and heavy crude oil and high quality products, offering likewise excellent opportunities for the participation of strategic foreign partners and national investors in the Venezuelan hydrocarbon business.
Evaluation of Fracture Stimulation Treatments by Integrated Reservoir Description and Fracture Treatment Analysis in the Pecos Slope Abo Tight-Gas Reservoir, Southeastern New Mexico
Authors: Sanchez Steve , Engler Thomas W. , Kelly Mike
Published: December 2007

The primary goal of this study was to couple reservoir characterization of the Abo Formation with hydraulic fracture analysis and subsequently, to infer infill drilling potential. Two detailed case studies were investigated to reevaluate original hydraulic fracture treatment designs, to compare and evaluate fracture parameters, and to determine if the fracture treatments were providing sufficient reservoir stimulation.

Approximately 80 wells were studied in the southern part of the Pecos Slope Abo Field. Decline curve analysis was performed on all wells by a modified set of Fetkovich type curves. Analysis of this work show linear to near-linear flow in most cases with permeability values less than 0.1 md and variations in reservoir properties as is typically observed in low permeability reservoirs. These variations resulted in difficulty in evaluating infill drilling potential.

Evaluation of fracture stimulation treatments was accomplished by matching recorded surface treating pressure with a fracture propagation model. Unusually high initiation pressures were observed in the case study wells; initial stress state, vertical fracture growth, fracture toughness, perforation restrictions, and the development of multiple fractures in a single, bounded layer were evaluated as possible causes for the high initiation pressures. Results from this work showed the multiple fractures model providing the best match for the two wells. Fracture length varied from approximately 1150 ft to 750 ft with a single fracture model and was reduced by approximately 10 to 30% for each additional fracture added. The fracture data was input into a fractured well performance model, which was used to match the production rate and therefore verify the process.

The integration of decline curve analysis and fracture analysis provided better descriptions of reservoir properties and more accurate designs of fracture propagation models. This combined approach also improved evaluation of infill drilling potential by evaluating reservoir properties and stimulation.
Log Evaluation of Low - Resistivity Sandstone Reservoirs
Authors: Hamada G. M. , Al-Awad M. N. J. , Almalik M. S.
Published: December 2007

A careful examination of the mud log and sidewall cores in certain interval of hydrocarbon anomaly, dry oil from low resistivity sands was surprisingly discoverded and confirmed afterward by well testing results. The problem with these sands is that the resistivity logs indicate high water saturation, but water free hydrocarbon will be produced.

This paper discusses the different reasons sandstone reservoirs can have low resistivity. The mechanisms resposibles for low resistivity phenomenon are described as being caused by the inclusion of clay or pyrite minerals and as being due to microporosity. Clean bearing sandstone has high resistivity, but when this rock contains clay, or heavy minerals such as pyrite, the resistivity can become low. Pyrite shows a good electrical conductivity, that is usually comparable to or even higher than the conductivity of formation water, and can therefore have a larger effect than shale. In this work, different shaly sand models will be discussed and applied in two field examples to correct the calculated water saturation from shale effect to get the true water saturation level. The contribution of NMR log in solving problems of low resistivity microporisity sandstone reservoirs was iluustrated by a third field example.