bluuebunny/crossref_metadata_2025_split huggingface dataset:
Fracture Conformance Treatments Using RPM: Efficiency and Durability Evaluation
Authors: Díaz G. , Castillo P. , Villa K. , Sanchez L. , Mucci M. , Robles J. , Morris W. , Peacock H. 
Published: May 2009

Abstract
Water production control has become a key issue in most mature oil fields worldwide. Several water shut off technologies have been developed during the last two decades, and intensive research work is continuously conducted in this field. Relative permeability modifiers (RPM) have proven to be an effective method to enhance oil recovery, especially under linear flow conditions achieved after fracturing. This technique is being extensively used worldwide, with many successful case histories published in the literature. When adequately design and applied, RPM treatments will increase well profitability, improving water-oil ratio, reducing water management costs and environmental impacts. However, RPM treatments are not always effective, as they depend on several aspects associated to formation and fluid production characteristics, polymer chemistry and the interaction between each other.
Many oil and gas zones in Entre Lomas field require hydraulic fracturing for a profitable production. However, the risk of contacting close water layers might jeopardize wells productivity. RPM treatments have been conducted in this field since 2007. In most cases the RPM solution was pumped as part of a fracture conformance job. This paper presents the results from more than 50 wells fractured bull-heading RPM treatments.
The field work was supported by a laboratory study based on different experiments performed to evaluate RPM efficiency. Regain permeability (RK), relative permeability curves and nuclear magnetic resonance (NMR) tests were conducted using core plugs and Berea sandstone samples. The RPM polymer washout rate was evaluated by spectrophotometer measurements performed on brine samples collected during the flow test. The NMR spectrums run on treated and untreated cores in the saturated and irreducible water condition provided evidence of the polymer bonding capacity and its ability to retain water.
The use of RPM's allowed fracturing formations with close high water saturation transition zones that otherwise would not be produced. Pre and posfrac formation evaluations tests and production data is provided. Laboratory results show that the RPM polymer under study produced a significant reduction in water permeability, without substantial oil perm modification. Polymer wash out time showed strong flow rate dependence affecting the treatment durability.
Implementation of the New Directional Technology: Drilling, Measurement, and Mapping of Small Layers in Real Time in Lake Maracaibo, Venezuela
Authors: Pizzarelli Sergio , D'Windt Adolfo , Soto Mary , Orta Francisco , Calderon Erik , Hezboun Nidal 
Published: May 2009

Abstract
Prolonged depletion in mature fields renders oil and gas companies to tap more difficult reserves to access and produce. New directional LWD measurements are providing valuable technical support to geoscientists helping them to precisely locate and delineate layer boundaries and fluid contacts in real time. Furthermore, by means of LWD measurements, well trajectory is enhanced which is helping field operators to reduce capital spending by decreasing the probability of facing wellbore stability problems.
Horizontal well placement and trajectory is a critical issue when developing reservoirs based on this technology. Furthermore, reservoir depletion and well performance will be directly linked to well's construction's features. In order to attain these goals, real time azimuthal measurements are essential in helping to properly design, construct and terminate deviated wellbores in a prolific pay section.
PDVSA E&P has successfully applied such technology in reservoirs of 15'-20’ sand thickness achieving reduced risks in well placement and obtaining increased productivity indexes increasing oil output by 22%. Detailed description of field cases are shown along with tool's characteristics, benefits and drawbacks are illustrated with field data.
Exploitation Plan Design Based on Opportunity Index Analysis in Numerical Simulation Models
Authors: Molina A. , Rincon A. 
Published: May 2009

Abstract
The Opportunity Index Analysis is an intelligent method that uses numerical simulation models to identify zones with high potential of production, which with conventional reservoir engineering often represents a too complex and time consuming problem. This method reduces dramatically the required resources and the uncertainty to define these zones, being a practical tool to support the field development plan.
The producer potential of an area is calculated based on the basic rock and fluid properties, as well as the energy capacity associated with the reservoir pressure. All those parameters are combined and normalized, to generate the "Opportunity Index" between 0 and 1, capable to identify the zones of greater potential.
In order to calculate this index, three main variables are considered. First, the flow capacity of the rock, which combines the thickness of the cell with its effective permeability (k*h); the second is the hydrocarbon pore volume mobile (HCPVm), associated to the rock-fluid system, and the third is the gradient pressure of the reservoir, defined as the difference between the reservoir and the abandonment pressures.
One of the products of the methodology are the time depending Opportunity Index Maps by layer, that represents a invaluable tool in the optimization of secondary recovery processes as well as to define unsweep zones due to the low volumetric sweep efficiency or pressure equilibrium between wells. Those zones will be candidates for infill drilling, new wells geologically optimized or well production-injection patterns improvement.
The methodology was implemented with a commercial numerical simulator and applied in three mature reservoirs of the Neuquén Basin of Argentina. 3D maps were generated to identify sweet spots in the fields with time in order to define the most appropriate locations that may still have reserves to be produced, and a optimize exploitation plans were designed.
The Opportunity Index Analysis can play an important role in identifying new opportunities in mature fields and optimize the resources. In this paper, the new methodology is introduced and its application in three mature fields was demonstrated.
Evaluation of Streamline Simulation Application to Heavy Oil Waterflood
Authors: Osako I. , Kumar M. , Hoang V. , Balasubramanian G. 
Published: May 2009

Abstract
Lack of analogs and the nature of high mobility ratio waterflood conditions pose many difficulties for reliable performance forecasts for heavy oil waterflood. In many cases, although numerical simulation is the method of choice for forecasting, it also faces several challenges, including smaller grid sizes resulting in longer computation time.
In this study, we investigated streamline simulation (SL) as a potential method for heavy oil waterflood performance forecasting. Streamline is well known in the industry for its speed and its ability in minimizing numerical and grid orientation effects for light oil waterflood applications. Because heavy oil reservoirs generally have less free gas, small capillary and gravity forces, applications of the streamline simulation is promising. We used both mechanistic and field-scale models to delineate advantages and limitations of streamline simulations compared to the finite difference method (FD) for high mobility ratio waterflood.
First, we evaluated streamline simulation using 2D and 3D mechanistic models for the oil-water viscosity ratio range of 10 to 1000. The overall streamline results, in term of breakthrough time and oil recovery, are similar to that of FD, although some difference due to gravity treatment was observed. Further, streamline shows less grid orientation effects in homogeneous models. However, streamline method generates instabilities for viscosity ratios of 10 or higher that resulted in production profile oscillations. In addition, its results are sensitive to pressure update time step for viscosity ratios of 10 or higher, suggesting a sensitivity analysis of pressure updates needs to be done prior to a study.
Next, we applied the streamline method to a 3D heterogeneous segment of a heavy oil waterflood pilot project to verify the above observations. The model results confirmed the observations above. However, the streamline method does show computational advantage for large-scale field model with less frequent pressure update. Further, it also enhances the visualization of producer to injector connectivity.
When applied properly, streamline simulations can be a powerful tool for quick screening of heavy oil waterflood projects, estimating oil recovery, and water breakthrough time.
Case Study of the Application of Pressure Transient Testing to Characterize the Pumping Wells in the Calcutta Field in Suriname
Authors: Bhoendie K. S. , Moe Soe Let K. , Mohan A. , Azari M. 
Published: May 2009

Abstract
The Calcutta field in Suriname is comprised of shallow, low-pressure, heavy-oil sandstone reservoirs that are being produced by progressive cavity pumps. These reservoirs are difficult to characterize because of the complexity of the depositional environments encountered in the wetlands of Suriname.
The unconsolidated nature of these reservoirs makes it virtually impossible to recover any core successfully; hence, petrophysical parameters were originally derived from well-log analyses. Completions consist of gravel pack with screens to control the unconsolidated sands. Initial quality checks with surface liquid samples for PVT analysis routinely involve measurement of the bubble point pressure at ambient temperature. However, the emulsified water in the heavy oil made it difficult to conduct such PVT analysis.
The inability to obtain reliable core or fluid samples, made pressure-transient testing an essential tool for characterizing these reservoirs. After the initial operational and mechanical restrictions were resolved, a field-wide program was implemented in 2008. However, the quality of the recorded pressure data was adversely affected by frequent power failures that resulted in unplanned pressure buildup periods. The pressure transient analysis was also influenced by limitations in production data gathering during the flow periods. Additionally, uncertainty in fluid properties and problems with mechanical and pumping equipment caused undesirable pressure disturbances during the well testing periods.
Analyses of the tested wells showed better formation properties than suggested by the initial well-log-derived potentials, i.e., wells suspected to have formation damage proved to have negative skin, instead. Formation permeability was also found to be higher than the log-derived permeability values; this difference could have been caused by the gravel pack.
The geological interpretations were improved and uncertainties regarding completion efficiency have largely been eliminated. The results have contributed to a better understanding of reservoir performance and have led to increased production optimization efforts.
The field examples presented here illustrate the unique challenges experienced while applying pressure-transient testing in pumping wells to characterize the geologically complex reservoirs of the Calcutta field. This paper also describes the mechanical issues, well preparations, water production problems, and installation of permanent gauges in these wells.
Volcanic Submarine Deposit as Tight Gas Reservoir
Authors: Schiuma M. , Martinez V. , Monti L. 
Published: May 2009

Abstract
In the Neuquen basin, center west of Argentina, a tight gas field was developed in submarine volcanic rocks. The field called Cupen Mahuida is a faulted anticline, which produced oil and gas from the upper formations. This deeper reservoir was discovered in 2001. The average depth is 3500 m and there are 16 wells producing from these rocks. The production is dry gas with a low CO2 content.
Because the low permeability hydraulic fractures are needed to produce the wells and the productivity of them is highly variable. The pressure behavior during the fracture pumping showed the presence of natural fractures.
These highly variable results in the wells pushed to get a more predictable reservoir model, and then 99 m of cores, 58 sidewall cores and 8500 m of cuttings were described in detail. Based on the information obtained the geological model was adjusted. Was found that these rocks were originated in volcanic eruptions both sub aereal and submarine and the eruptive products were deposited in a water body. There were several volcanoes feeding the area and were located about 20 km away from the deposits, and then the deposits have a distal position from the volcanoes. A probable volcanic center in the NE of the field was identified. Only one event has had sub areal exposition and could be use as a local correlation level.
Micro fractures due to cooling, gas escapes, etc that are common in this kind of rocks when they are deposited sub aerealy are not present. The primary porosity was completely occluded and the current porosity is due to mineral dissolution. Open natural fractures are present but the density is low as well as the fracture width, some tectonic micro fractures were identified.
Conclusions:
The detailed rock analysis allowed to define the depositional environment, this knowledge changed the approach to analyze the porosity distribution. There are micro fractures, although this is not the largest source of porosity, primary porosity was destroyed because the rock alteration, the main porosity source came from the mineral dissolution.
3D Seismic Application in Remodeling Brownfield Waterflooding Pattern
Authors: Amaya R. , Nunez G. , Hernandez J. , Gambaretto W. , Rubiano R. 
Published: May 2009

Abstract
The Casabe Field has been supported by Waterflooding as Secondary Oil Recovery method for 23 years now. In Addition, the reservoir has some particulars characteristic like; high heterogeneous sandstones, low lateral continuity, swelling shale and high structural complexity.
Since the beginning of the waterflooding project there were some problems in the field like; preferential injection, low injectivity, repressure reservoirs, which have caused casing collapse, lost of producer wells and low recovery factor. Along the time, the field was managed with a traditional geological model built with wells, which limited the production and injection surveillance.
Between 2007 and 2008, a 3D seismic cube was acquired, processed and interpreted for the whole field, covering an area of about 100 km2. With this new information, a detailed structural geological model was built, what allowed visualizing new development areas and optimizing the production and injection process which boosted the oil production and increased the oil reserves.
This paper covers the implemented methodologies and solutions about waterflooding pattern remodeling starting from seismic cube as a seismic inversion product that generate a stratigraphic model and more reliable facies distribution. At the same time this interpretation was used to implement and design the flooding strategy in the new zones, producer wells completion optimization and well selective injection design, abandoned pattern reactivation, explanations about unusual production and injection phenomenon and expand waterflooding implementation in new areas
This process resulted in the incorporation of 5 MMbls of oil as proven reserves, 20 MMbls of oil as probably reserves and 5 MMbls of oil as possible reserves.
A Workflow for Integrated Barnett Shale Gas Reservoir Modeling and Simulation
Authors: Du C. , Zhang X. , Melton B. , Fullilove D. , Suliman B. , Gowelly S. , Grant D. , Calvez J. Le 
Published: May 2009

Abstract
The Mississippian Barnett Shale reservoirs have opened a new era for US gas production. Many reservoir characterization efforts have been made and completion practices established to help understand the Barnett Shale reservoirs. The borehole image interpretation, drilling-induced fractures and conductive/healed fractures, reveals stress regime orientation, fracture morphology and their orientations. The interpreted results guide the design of horizontal wells to control hydraulic fracture directions and intensities. Conventional logs and cores have been used to classify lithofacies and estimate petrophysical and geomechanical properties for well positioning and reserve calculations. The seismic survey is not only interpreted for structure horizons and faults, but also analyzed for 3D property evaluations such as lithofacies distribution, discrete fracture network, and stress field. On the operation side, longer horizontal wells are drilled and massive multistage, multicluster hydraulic fracturing treatments (HFT) are executed. Various well placement and HFT schemes are performed. The microseismic (MS) has played an important role in understanding the estimation of hydraulic fraturing stimulated reservoir volume (ESV) and fracture intensities.
In spite of this tremendous effort and progress, a systematic methodology appears lacking in the literature to integrate the variety of information and obtain accurate reservoir characterizations. In this paper, we present an integration workflow that incorporates seismic interpretations and attributes, borehole image and log interpretations, core analysis, HFT, and microseimic data to construct reservoir models and discrete fracture networks that are then upscaled to dual-porosity reservoir models for numerical simulation. The application of this workflow in field studies has revealed important observations and provided better understanding of the reservoirs.
This integration workflow demonstrates an effective methodology for capturing the essential characteristics of Barnett Shale gas reservoirs, and offers a quantitative means and platform for optimizing shale gas production.
Casing Collapse Study on Block VI Wells: Casabe Field
Authors: Olarte P. , Marquez L. , Landínez G. , Amaya R. 
Published: May 2009

Abstract
This document presents the development and results of a study for determining the possible reasons of casing collapse in the Casabe Field, Colombia, specifically in block VI, where the phenomena occurred with more intensity.
The study was requested as part of a revitalization strategy for this mature field, to maintain and improve the production performance of new and existing wells.
The study consisted of different phases: Statistical and Probabilistic: firstly related to trend identification (i.e. well type, drilling date, well status and collapse localization), and secondly reliability and failure curves were created using the probabilistic Montecarlo analysis.Mechanical Integrity: casing integrity was analyzed using a software application called TDAS, by taking into account the corrosion effect and different operational and typical loads.Water flooding effects were also analyzed to take into account the stresses created by water injection on the casings at different formation levels (A or B).
Figure 1 shows the four main phases that comprised the study.
As a result of this study, a new well mechanical design was created and successfully applied on all new wells drilled in the Casabe field with zero collapse occurrences.
Well longevity has been guaranteed, improving the economics of the field.
The study gives a safety operational procedure considering a range in different parameters (tension, fluid level, corrosion, injection pressure and type of casing) that give support to critical well operations in order to mitigate casing collapse.
Inversion Feasibility of Elastic Parameters in Heavy Oil
Authors: Garcia S. , Gasbarri S. , Gimenez J. 
Published: May 2009

Abstract
Heavy oils are an important energetic resource because they represent a significant part of the world reserves. The countries with the largest quantity of these resources are: Canada and Venezuela. Several studies have been done on heavy oils and they express the influence of the temperature, viscosity and density on velocities and the frequency content of the signal propagating through the reservoir (Batzle and Hofmann, 2006; Behura et al., 2007; Han and Liu, 2007). These investigations have shown that the relationships developed for conventional oils cannot be applied for heavy oils. The aim of this research was the evaluation of feasibility of elastic parameters estimation in heavy oil using prestack seismic inversion. In particular, the estimation and quantification of S impedance and density, which are essential properties to describe heavy oil. The results of this study show that the estimation of elastic parameters is possible under certain conditions. In fact, beginning with the design of the seismic survey up to the processing sequence must be taking into account.
The significance of this study relies on the evaluation of a geophysical methodology which allows the integration of different kinds of data, not only to reduce the uncertainties but to get a better imaging of the reservoir under study. In the same way, this technique allows to optimize the well location and a better understanding of the reservoir.
Sanding Prediction in a Gas Well Offshore Mexico Using a Numerical Simulator
Authors: Pacheco E. , Soliman M. Y. , Zepeda R. , Wang J. , Settari A. 
Published: May 2009

Abstract
Sand production is a problem that plagues many reservoirs and has strongly affected benefit-cost relationships in the oil industry for years. Research dating as far back as the early 1930s has documented sand-production problems in unconsolidated formations.
These problems are not related to one specific location or area, and although sand production is a worldwide problem, the major documented areas of sand production are in the USA, Canada, the North Sea, Europe, Venezuela, Bolivia, Brazil, and Colombia. Major causes of sand production include depletion, a change in flowing fluids, a change in stresses, and wellbore-stability failure.
Failure to manage sand production can have a significant impact on the productivity of the well with the possibility of causing an eventual well collapse.
In this paper, the application of a numerical simulator used for sand prediction in a gas well is presented. The simulator predicts the amount of produced sand and its effect on the productivity of the well. The model is based on the hydro-erosion model, first proposed by Vardoulakis in 1996 (Vardoulakis et al. 1996). The model is based on rigid, porous media (no skeleton deformation), in which mass balance is applied to a three-constituent system comprised of solid, fluid, and fluidized solid using the homogenization-mixture theory. Subsequently, Wan and Wang (2002) extended this pure-erosion model to include the effects of the deformation of porous media in a consistent manner. A single-phase flow is iteratively coupled with geomechanics within a continuum mechanics framework. Furthermore, Wang (2004) extended previous work to develop a fully coupled reservoir-geomechanics model to account for the effects of multiphase flow and geomechanics in a consistent manner.
By using this numerical simulator application, the severity and quantification of the problem of sand production were resolved, resulting in an acceptable economical return. The results of this field case are documented below in further detail.