bluuebunny/crossref_metadata_2025 huggingface dataset:
Inaccurate Gas Viscosity at HP/HT Conditions and its Effect on Unconventional Gas Reserves Estimation
Authors: Davani E. , Ling K. , Teodoriu C. , McCain W. D. , Falcone G.
Published: May 2009

Viscosity is one of the gas properties that is always uncertain at high-pressure and high-temperature (HPHT) conditions because no reliable correlation has been developed for HPHT and accurate measurement of gas viscosities at HPHT is difficult. However, the industry currently does not pay sufficient attention to the need for accurate gas viscosity values in HPHT gas fields’ development.

We show that small errors in gas viscosity affect the inflow performance relationship (IPR) curves and eventually change the reserves estimate for HPHT conditions in ways that can drastically influence production forecasting. A sensitivity analysis for a synthetic case at these conditions shows that a 1% error in gas viscosity measurement results in a 1% error in gas flowrate, which in a large scale of gas production may severely underestimate or overestimate recovery from an HPHT field. This linearity between gas viscosity and gas flowrate continues to ±10% errors.

An evaluation of gas viscosity correlations commonly used in the industry shows that none of them is reliable at HPHT conditions, mainly for two reasons: measured data are not available to confirm their consistency and they do not account for impurities in the gas.

Clearly, the industry needs accurate gas viscosity measurements and needs a new procedure to develop correlations based upon accurate HPHT gas viscosity data.
Slug Catcher Conceptual Design as Separator for Heavy Oil
Authors: Marquez J. , Manzanilla C. , Trujillo J.
Published: May 2009

The gas-liquid separation processes in the heavy and extra heavy oil fields are performed mainly with gravity conventional separators. However, the separation efficiency of these equipments depends on the operating conditions, the appropriate design and the properties of the fluids. Thus, in heavy and extra heavy oil fields, the separation efficiency is affected due to of the handle liquids of viscosity high, low pressures and low gas flow rate. Additionally, these conditions increase the probability of slug flow formation through pipelines that causes operational problems, mainly in the separation process.

In response to this situation, arises the need to design a gas-liquid separator able to handle viscous liquid, reduce the effects of slug flow and perform an efficient separation. In this sense, there are different technologies that can help to improve the gas-liquid separation, among them is found the finger type slug catcher. This technology is usually used in gas fields or light and medium oil fields as conditioner flow and slug flow mitigator. However, this paper has changed this focus for considering a design for heavy oil.

This paper presents an improvement in the methodology of Sarica et al. (1990) to predict the dimensions of finger type slug catcher to use in heavy oil fields. It is based on the effect from the transition of stratified flow to non-stratified flow when the liquid phase is viscous and only considers slug flow characteristics under normal flow. Based on the improvement the required diameter and length of the finger are determined.

The improvement is used to design a finger type slug catcher for heavy oil field conditions in Orinoco Belt and an economic comparison against conventional separators is presented. The comparison demonstrated that the finger type slug catcher designed with the proposed method is less expensive than the conventional separator.
A 3D Seismic Cube: What for?
Authors: Gambaretto W. , Peralta J. , Cortes G. , Suter A. , Dederle M. , Guarnizo E. Lozano
Published: May 2009

We have already more than X hundreds wells!!

We do not need a seismic cube now, do we?????

Who has not heard that kind of exclamation/question while working in oil/gas field development??

Casabe oil field was not the exception. Discovered in 1941, it's been in production since 1945. It cumulated 297 MM bbl of oil (October 2008) with more than 1100 wells drilled.

Since 2004, it's been operated by an Alliance formed by Ecopetrol and Schlumberger.

A 3D seismic cube was shot during the first half of 2007. By the middle of 2008, the seismic cube had been loaded and interpreted and by October of 2008 the production had been boosted more than 50%.

The reasons….?. Two main reasons: Seismic cube dataSelective string water injection

Of course: The second can not be properly implemented without the first.

By having a 3D seismic cube we were able to: Develop a precise and reliable structural modelDefine more accuratelly W/O contactsDefine more accuratelly the size of the fieldDesign more accurately well trajectoriesProperly place injector/producer wellsDesign more accurately the injection patternsEstimate reservoir quality: Seismic Inversion dataCompute gas reserves: Attribute-AVO analysisIncorporate undeveloped areasDiscover a new prospect

In other words it was possible to: Get more precise reserve picturesIncorporate: 10 % of the OOIP
Casabe Mature Field Revitalization through an Alliance: A Case Study of Multicompany and Multidiscipline Integration
Authors: Marquez L. , Elphick J. , Peralta J. , Amaya M. , Lozano E.
Published: May 2009

This paper summarizes the achievements of an alliance between Ecopetrol, S.A. and Schlumberger to revitalize the Casabe field, a mature field located in Colombia.

Challenges have been multifaceted in this mature complex field. Some relate to the heterogeneous nature of the reservoirs, limited sand continuity, unfavorable mobility for the waterflooding ongoing process, associated sand production, and wells lost due to collapses.

Parallel efforts on fast-track studies and field development planning (FDP) were performed. The FDP incorporates technology application such as: 3D seismicNew geological modelNew correlation in detailed scaleDrilling in fresh oil areas, infill, and new structuresSelective water injectionNew waterflood design and monitoringStrong increment of water injected by pattern.

From 2004 to 2008, the integrated project has increased the oil production from 5,200 BOPD to 11,900 BOPD with a reserves replacement ratio of more than 100% per year. All these factors provided extension to the life of this complex field while bringing additional financial benefits for the partners.

The article presents the FDP planning methodology, that overall proved to be useful and repeatable for other fields.
A New Approach to Improve Waterflood Predictions After Breakthrough: Field Case, Maracaibo Lake, Venezuela
Authors: Soto B. R. , Pérez V. O. , Soto O. D. A. , Hocol S. A. , Montiel E.
Published: May 2009

One of the most important parameters calculated by reservoir engineers in a waterflood project is the variation of average water saturation with time to estimate the recovery factor. For years, this average water saturation after breakthrough has been obtained by finding the intersection of the tangent to the fractional-flow water saturation curve, fw vs. Sw, at fw = 1.0. However, this technique is subject to errors because it is difficult to determine the exact point where the tangent to the fractional flow curve intersects the curve.

This paper discusses the development of a new function that matches with all fractional flow calculations from relative permeability displacement data to oil-water viscosity ratios. This new function has four parameters that vary according to the mobility ratio. The advantage of this new function is that its derivative can be used to calculate the average saturation after breakthrough, giving more accurate results when estimating waterflood predictions and the volume of oil displaced. If we use this new function technique along with rock type distribution, assigning a relative permeability curve to each rock type, it is possible to evaluate the possibility a waterflooding project with high certainty.

We present the procedure for determining the four parameters of this new general function and the advantages of its application through field examples from reservoirs in literature and from reservoirs in Maracaibo Lake, Venezuela.
Alternate Power and Energy Storage/Reuse for Drilling Rigs: Reduced Cost and Lower Emissions Provide Lower Footprint for Drilling Operations
Authors: Verma A. , Burnett D.
Published: May 2009

One of the major ways to reduce the footprint of drilling operations is to provide more efficient power sources for drilling operations. Rigs powered by the electrical grid can provide lower cost operations, emit fewer emissions, are quieter, and have a smaller surface footprint than conventional diesel powered drilling.

This paper describes a study to evaluate the feasibility of adopting technology to reduce the size of the power generating equipment on drilling rigs and to provide "peak shaving" energy through the new energy generating and energy storage devices such as flywheels.

An energy audit was conducted on a new generation light weight Huisman LOC 250 rig drilling in South Texas to gather comprehensive time stamped drilling data. A study of emissions while drilling operation was also conducted during the audit. The data was analyzed using MATLAB and compared to a theoretical energy audit. The study showed that it is possible to remove peaks of rig power requirement by a flywheel kinetic energy recovery and storage (KERS) system and that linking to the electrical grid would supply sufficient power to operate the rig normally. Both the link to the grid and the KERS system would fit within a standard ISO container.

A cost benefit analysis of the containerized system to transfer grid power to a rig, coupled with the KERS indicated that such a design had the potential to save more than $10,000 per week of drilling operations with significantly lower emissions, quieter operation, and smaller size well pad.
Economic Analysis Using a Real Option Model in an Exploratory Project
Authors: De Abreu C. C. , Cavalcante Filho J. A.
Published: May 2009

The Real option Valuation theory is based on the concepts of the options traded in stock markets applied to real projects, where those are considered options of investment. The methodology enables the valuation of a manager's flexibility to adapt and review his estimates for investment decisions if market or project's processes have any change. Real Option Valuation considers flexibility caused by uncertainties as a key point of an economic analysis of an investment.

This paper intends to develop a real option valuation model to be applied in investment opportunities where uncertainties related to the initial production rate and the decline rate are key variables, considering an exponential decline. We consider a scenario where we have an exploratory project with high leves of uncertainties regarding possible future production. Based on exploratory information about the field the company will decide if it will develop the reservoir or not. These uncertain variables are modeled by stochastic processes causing impact on the production of an oil field and in its economic returns as a result.

The model's main idea is the definition of a decision-making rule including the valuation of the flexibility from the possibility of delaying an investment in an oil field due to better geological information. We used a continuous time real option model to estimate the option value and investment trigger point and compared the results to estimates from evaluation using traditonal discounted cash flow economic analysis methodology.

The evaluation model is applied to a set of production curves based on real production data from a producing reservoir located in the Brazilian northeastern coast. Preliminary results show that the investment – rule is different from that of traditional NPV, that is, insvest as long as NPV > 0. The methodology can be used as an additional economic analysis decision-making tool to help managers decide in an uncertain production environment. This model does not eliminate the traditional evaluation methodology.
An Integrated and Systematic Revitalization of a Mature Asset
Authors: Maldonado G. , Gomez U. , Degiorgis G. , McLeroy P. , Sharifi A. , Sharry J. , Chow C.
Published: May 2009

The Vizcacheras License in Mendoza Province, Argentina, is a complex multi-reservoir asset within YPF's mature asset portfolio. Facing a current recovery factor averaging 46+% between the producing reservoirs, YPF embarked on a program to enhance recovery and maximize asset value. Vizcacheras, discovered in 1962, stands with 400 wells in 2 structures with homogenous and heterogenous reservoirs and operated by 4 different organizations. Peak production was 38,000 bopd; currently producing 10,000 bopd with water cut of 97%. Beyond the geologic complexity, was the commercial challenge rejuvenating the field under mounting operating costs. YPF decided to respond by assessing: if the field had stranded value; the magnitude of stranded value; and, method(s) to deliver value. A multi-disciplined YPF and Arthur D. Little team was formed to assess the Vizcacheras license from subsurface through surface employing innovative technical systems analysis to build a risk-based field development plan.

The focus of revitalizing a mature field is to define a customized asset evaluation approach to quickly manage large amounts of data and identify key mechanisms for stranded value and value-added solutions, while minimizing costs. The team captured this through innovative systems planning and operation, displacing the traditional lab-to-field R&D search in that multiple options were generated from within functional technology contributions.

The result is convergence toward multiple enhanced recovery and operational changes that are anticipated to yield increased recoveries and more efficient management of the asset. Diagnostic analyses of production profiles from individual wells and patterns of wells identified zones of poor reservoir sweep and bypassed oil, guided by large-grid simulation models aimed to reduce risks. Uplift opportunities from pump optimization, infill drilling, injection and adjusted secondary recovery patterns were identified using a risk-based value analysis, with an anticipated increase in recoverable oil of 3%. EOR strategy work is currently underway in which YPF envisions up to three times the recent optimization results.

Use of a ground up approach to gather, quality check, and integrate data to build models of the geological framework and to conduct quantitative engineering analysis of the system's performance is showing added recovery benefits from the integrated workflow as it is implemented.
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

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

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

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

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

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

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

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

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

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

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

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.
MPD Concentric Nitrogen Injection Used to Drill a Successful Horizontal Well in Fractured and Depleted Mature Reservoir in Mexico South Region
Authors: Perez-Tellez C. , Urbieta A. , Lupo C. , Castellanos J. M. , Ramirez O. , Puerto G. , Bedoya J. , Gabaldon O. , Beltran J. , Castiblanco G.
Published: May 2009

This paper will focus on design, planning and execution process followed to apply managed pressure drilling (MPD) using a Concentric Casing nitrogen Injection to drill a high angle well in a fractured carbonate mature field. It will be shown how steady state multiphase flow modeling was used to find operating envelope in terms of ECD and hole cleaning and transient flow simulations to predict and select the best parameters to avoid well slugging and pressure instability.

Formation pressure of this flied have been decreasing over the last 25 years with current values down to 0.4 g/cm3 SG. During the previous years, MPD techniques had been implemented using Nitrogen injected through Drill Pipe to overcome operational problems like mud lost circulation and differential sticking. However the high volume of nitrogen inside the drill pipe generates important limitations for conventional MWD tools, but also the use of Electromagnetic tools has limitations in some cases due to high bottom hole temperature or formations resistivity. This situation has restricted the implementation of high angle and horizontal drilling due to reduced possibility to control the trajectory to reach the target in this kind of wells. Three horizontal wells have been previously drilled in this field without very good results. Nevertheless, horizontal wells are required in order to keep the production level above the forecasted declination. Intelligent drill pipe appeared as another option, but also the tools still will be affected by temperature with gasified system.

The nitrogen concentric injection technique was analyzed as a solution to make feasible the use of conventional mud pulse MWD/LWD tools and keeping at the same time bottom holes circulating pressures within the operational window required to avoid circulation losses, assure good hole cleaning and control risk of hole instability.

Once it was determined the feasibility of this technical option, extensive planning sessions were carried out to design specific operational procedures for this application. It was based on steady state and transient flow modeling assuming different operational parameters to evaluate the expected performance of the operation. Exhaustive Risk Analysis and rigorous class room and rig site training were developed to make all the personnel involved in the operation familiar with the desired understanding of the project.
New Method for Extraction Oils and Greases From Produced Water Using Microwave Techniques
Authors: Bezerril R. H. , Ramalho A. M. Zanbotto , Souza K. R. , da Silva D. R. , da Mata W. , Barillas J. L. M.
Published: May 2009

In determining the Oils and Greases contents (TOG), one of the most important step is the extraction procedure, because at this stage occur the segregation of oils and greases from water produced. It is noteworthy that some samples with low levels of TOG in their composition often are not determined by the standard method of reference. In this case, it is essential the availability of a technique that allows the detection and quantification of these low levels. For this reason, this work aims to optimize the determination of oils and greases using a technique of microwave extraction, followed by the determination in the Infrared Spectrometry through the analyzer Infracal TOG/TPH. The evaluation of the efficiency of the proposed methodology was performed by comparison with the conventional technique whose the extraction of organic matter (oils and greases) is done by manual agitation. However, the basic principle of the technique by microwave radiation is in the process of heating/cooling the sample to promote a more efficient extraction of organic matter. The two techniques were evaluated through the following parameters: sample-solvent proportion and time of extraction at 2, 4 and 6 minutes. According to the comparison of results between them, was observed that the replacement of manual extraction by microwave one was more efficient.
A Practical Numerical Approach for Modeling Multiporosity Naturally Fractured Reservoirs
Authors: Arana V. , Pena-Chaparro O. , Cortes-Rubio E.
Published: May 2009

This work presents a very practical and simple technique to numerically simulate the multiphase flow in multiporosity naturally fractured petroleum reservoirs. A correct modeling of Naturally Fractured Reservoirs requires both good understanding of the physics of the flow through the formation and its correct implementation in a Numerical Reservoir Simulator. Some history matches in Naturally Fractured Reservoirs have showed that the traditional double porosity formulation used since the end of the 60's sometimes does not show good results.

Even though the modeling of naturally fractured reservoirs has been developed through more than five decades, there is still and will be a considerable research activity to obtain a practical and robust modeling for this type of reservoirs.

The proposed method assumes a nested serial flow among the different porosity systems that have been identified. Only the most outer porous medium is considered as continuous and therefore, it carries the flow to the producing wells. The rest of the systems are considered discontinuous, interacting themselves only locally. After applying the Newton method to the discretized system of nonlinear equations, a tri-diagonal matrix block structure is obtained, which is reduced by applying cyclically the Schur complement. This algorithm can be implemented straightforward in a non-fractured multiphase reservoir simulator. It is shown that this approach can model any multiporosity naturally fractured reservoir as long as the fluid transfer functions between mediums could be represented by the quasi-steady-state flow assumption, which is the Warren and Root model.

Results show that the behavior of multiporosity reservoir simulated as double porosity systems result in non-realistic reservoir performance and therefore wrong make-decisions.
New Product for Inhibition of Calcium Carbonate Scale in Natural Gas and Oil Facilities Based on Aloe Vera: Application in Venezuelan Oilfields
Authors: Castillo L. A. , Torin E. V. , Garcia J. A. , Carrasquero M. A. , Navas M. , Viloria A.
Published: May 2009

Scales are secondary deposits constituted by inorganic chemical compounds present in an anthropogenic system. They are generated by changes in the thermodynamic, kinetic and hydrodynamics conditions[1] when formation fluids are produced, or by mutual physicochemical incompatibility between production and injection fluids. Therefore, they can jeopardize the integrity, good condition and useful lifetime of geological formations, producing and injection wells, surface facilities and pipelines, increasing the industry operation costs.

Generally, these problems had been mitigated by using conventional technologies based on chemical compounds (polyphosphate, carboxylic compounds, among others), that generate environmental liabilities and represent high costs for the industry.

Recently, PDVSA Intevep, S.A. has developed a scale inhibitor product based on Aloe vera plant chemical component[2], that offers equal or in some cases better efficiency than conventional chemical treatments, on the same conditions of evaluation. In addition, it offers the potential benefits of a lower environmental impact.

In this study, the performance of this anti-scale polysaccharide-based product was evaluated in the laboratory, simulating oil and water transfer system from flow stations to tanks, producing wells with high water content and injection wells. After, the product was evaluated in pilot field tests in two wells during about 50 days each: Barinas's production well with about 3200 BPD, 98% water and high scale tendency by Oddo-Thompson method at bottomhole.Monagas's production well with about 2200 BPD, 74% water and high scale tendency by Stiff and Davis method at wellhead.

In both cases, the pilot field tests were successful. The scale inhibitor product developed was more efficient than commercial products used in those production wells.