bluuebunny/crossref_metadata_2025 huggingface dataset:
An E-Line Solution to Sand and Scale Remediation in High-Angle Wells
Authors: Schwanitz Brian , McKay Alex
Published: December 2007

Sand accumulations in high angle wellbores inhibits production, plugs completions, erodes hardware and blocks access to downhole jewelry, such as valves and sliding sleeves. Bailing on sick line wire is the preferred, low cost method to clean sand and debris in vertical wells but slick line can not often reach in high angles. Conventional remediation methods for high angles use either Coiled Tubing or an expensive rig to remove sand and debris. This paper presents a rigless alternative to sand, debris or scale removal utilizing a combination of well tractor technology and a new vacuum/bailer system all conveyed on electric wireline.

Tractor technology is a proven tool as a conveyor of services in high angle wells. Combining a tractor with a well cleaning system provides the means of accessing and removing debris either selectively in one run or over a general area in multiple runs. These electric line powered tools can be mobilized quickly with less crew, and for far less cost than a coiled tubing mobilization. Following the sand removal, evaluation of the source of the sanding problem can then be performed with E-line inspection services during the same rig up.

Three case examples will be presented demonstrating the three different cleaning methods: liquid environment vacuum system, dry environment auger system and scale milling system. Each example will detail the unique cleaning head and bailer system used for the given completion and problem.
A Process Delivery Template for an Underbalanced Coiled-Tubing-Drilling Project From Concept to Execution
Authors: da Silva T. P. , Kavanagh T. , Rennox J. , Savage P. , Capps J.
Published: December 2007

Underbalanced coiled tubing drilling (UBCTD) has been utilized more frequently in recent years and can provide significant economic benefits when applied in the proper field setting. UBCTD requires a comprehensive evaluation of the proposed application, a commitment of resources by the operator and service providers, and a clear understanding of, (and tolerance to), the learning curve. As established coiled tubing drilling operations continue to push the technical limit forward, advances are assured.

The main scope of this paper is to document a template or flowchart for putting together a UBCTD project, covering everything from initial concept up to drilling the first well.
Production Optimization With Intelligent Wells
Authors: Emerick Alexandre Anozé , Portella Ricardo Cunha Mattos
Published: December 2007

This paper describes an implementation of method to optimize the production in intelligent wells varying the wells inflow control valves settings using an optimization algorithm coupled to commercial flow simulators. The optimization is based on direct search methods. The optimization algorithm was coupled with two different commercial flow simulators and has been applied in two real Brazilian offshore fields to quantify the benefits of intelligent wells over a base case with conventional completion. The first field has three horizontal wells, two producers and one water injector, completed in two zones totalizing six inflow control devices. In this case, different scenarios have been analyzed varying the downhole valves type – on-off and multi-position. The results have shown that the intelligent wells scenarios increased the recovery factor and reduced the production and injection of water when compared with the base case (conventional completion). The second field has fifteen wells – nine producers with binary valves and six water injectors with six-position valves – producing and injecting in two or three zone totalizing 39 downhole valves to be optimized. In this case, the results have shown a significant increase of the expected cumulative oil production when compared with the base case.
Classic Models of Calculation of Influx: A Comparative Study
Authors: Marques J. B. , Trevisan O. V. , Suslick S. B.
Published: December 2007

Reservoir engineers usually work under much uncertainty. Among the several sources of uncertainty in reservoir management, calculation of the water influx from adjacent aquifers is undoubtedly one of the most important. Several models have been proposed for quantifying the influx of water accumulated into the reservoir. Among the classic models, the most used are van Everdingen & Hurst, (1949), Hurst modified (1958), Fetkovich approximate (1971), Carter & Tracy (1960), Allard & Chen (1984), and Leung (1986). This work will deal, in a comparative way, with the total influx of water by the aquifer performance as a function of time, taking as the base case the model proposed by van Everdingen & Hurst (1958), because this is the best in terms of solution of the diffusive equation. All analyses in this work were done in computer spreadsheets using the equations proposed by the authors of each model. In this comparison it is possible to analyse the water influx into the reservoir as a function of time, and the relative error of each model against the base model. Besides the instructional value of summarizing in a single paper several classic models of aquifers, one additional purpose of this work is to alert against the inadequate use of the Fetkovich model, as commonly found in flow simulators and in material balance programs, when the ratio between the radius of the aquifer and the radius of the reservoir is below 12. In the conclusions, some corrections of mistakes found in tables and formulations published in the original papers are presented, as well as alternative formulations for the calculation of the aquifer productivity index, specifically with regard to the original publications of Fetkovich, 1971 and of Leung, 1986.
Placement of Permanent Downhole Pressure Sensors in Reservoir Surveillance
Authors: Izgec B. , Cribbs M. E. , Pace S. V. , Zhu D. , Kabir C. S.
Published: December 2007

This paper probes the gauge placement issue with regard to yielding quality formation parameters, unaffected by wellbore effects. Non-physical or biased results may result if the wellbore effects go unaccounted for.

We used a wellbore/reservoir simulator, which conserves mass, momentum, and energy to develop a comprehensive understanding of the gauge-placement issue. First, we reproduced a field example from a deepwater asset to demonstrate the simulator's capabilities. In this example, we matched the bottomhole pressure, and pressure/temperature monitored about midpoint of the flow string during a multirate test sequence lasting some 60 hours. Calculations show that thermal effects are exacerbated by increasing flow rate and increasing gauge distance from the perforations.

Second, we performed a detailed uncertainty analysis with experimental design. Variables included in this analysis were perforation-to-gauge distance, permeability, geothermal gradient, flow rate, fluid viscosity, thermal conductivity of annular fluid and formation, and mechanical skin. This analysis sheds light on relative importance of these variables on our ability to extract formation parameters. Simple correlations are developed for designing gauge placement in many environments.
Economic Viability of Gas-To-Liquid Technology
Authors: Garrouch Ali A.
Published: December 2007

The Gas-to-Liquid (GTL) industry is witnessing a monotonic growth that is expected to increase the liquid fuel production from currently 51,000 bbl/day to approximately 1.3 millions bbl/day by year 2015. GTL appears to be a viable and promising solution for the future of alternative and cleaner energy technologies. Recent advances in GTL technology have lowered the cost to the level where GTL plants are profitable at crude oil prices of $23/bbl, for a 10% rate of return, and an annual operating expenditure (OPEX) that is 7% of a $40,000 per-barrel-a-day capital expenditure (CAPEX). Technology advancements, reflected mainly in the reduction of the capital costs are likely to lower this price to about $11.5 for a 10% rate of return and a 7% OPEX of a $20,000 PBD CAPEX. At a current CAPEX value of approximately $35,714 BPD for a number of oil companies, crude oil price lower than $20/bbl would place this particular GTL venture in an area of economic uncertainty.

The expansion of the GTL industry is likely to place the GTL industry in direct competition with the liquefied natural gas (LNG) industry for access to natural gas supply. By year 2015, GTL units are likely to consume about 4.75 tcf/year and LNG units will consume approximately 7.25 tcf/year. Together, this represents a fifty-year consumption of 600 tcf from the world natural gas reserves. This fifty-year consumption of both GTL and LNG plants represents only 20% of the proven stranded gas reserves that currently stand at about 3006 tcf. The global GTL industry will consume about 8% of the world stranded natural gas reserves, or 4% of the world proven natural gas reserves, for the same 50-year production-period. These statistics indicate that there are plenty of gas resources for the continuity of both the GTL and the LNG industries in the long term future.
A Novel Improved Condensate-Recovery Method by Cyclic Supercritical CO2 Injection
Authors: Millán Arcia Einstein , Gerder Y. , Gil J.
Published: December 2007

In the Eastern Venezuela gas assets, mid to long term planning business portfolio considers an increasing gas production potential and recoverable reserves under secondary or improved recovery methods. Most gas reservoirs are originally under or near saturation pressure. Native thermodynamic conditions along with typical production practices favor in-situ liquid condensation, leaving behind considerable non-recoverable liquid hydrocarbons. This liquid condensation is triggered by unfavorable pressure gradients developed under natural production as reservoir static pressure drops below saturation pressure, primarily in the near wellbore region. In addition, as gas expands due to the adiabatic real-gas-expansion Joule-Thompson effect, a reduction in the surrounding temperature is also expected. This effect, in turn, often favors a sharp reduction in the relative permeability to gas when "In Situ" liquid condensation takes place at interstitial level hence promoting a drastic decay in the gas productivity. Consequently, a considerable amount of liquid hydrocarbon is left behind in the reservoirs.

Based on the nature of the experimental findings, the availability for flue gas in the Eastern Venezuelan region, and the environmental concerns, a breakthrough improved Condensate Recovery (ICR) project is being considered by "Cyclic Supercritical CO2 Injection".

The cyclic nature of the process combined with the favorable equivalent density for the CO2 at reservoir condition is expected to positively impact thermal diffusion and accelerated mass transfer processes respectively mainly in the near wellbore region. In this project, pilot temperatures are expected to be in the range of 350 to 450 °F.

A combined effort to integrate experimental results into a numerical model was undertaken. A number of laboratory tests were programmed to typify both fluid and rock interactions and also to characterize the thermodynamic profile for the CO2 and In Situ live fluid.

The interaction coefficients of the equation of state (EOS) for the enhanced process were experimentally characterized reproducing the multiple contact events between the in situ liquid hydrocarbon and the foreign fluid (CO2) as a function of temperature.

Expected sweep efficiencies and residual liquid saturation after multiple contacts with CO2 were experimentally determined via core displacement tests using actual core samples. Soaking time extent was also optimize for energy diffusion purposes.

At a second stage, a single well model will be assembled, to numerically reproduce the experimental results, to match primary depletion and to predict enhanced recovery production profile. For field implementation, a pilot area was selected in the Santa Rosa Field belonging to Petroleos de Venezuela assets.
A Case Study of Latest Technologies Enables Successful Completion of ERD Exploration Project Off the Coast of Tierra del Fuego
Authors: Kulakofsky David , Oliveira Alessandro , Almaraz Angel
Published: December 2007

To help satisfy the demands for petroleum products, operators are being forced to drill in increasingly challenging environments. Combine cold winters, some of the strongest winds in the world, and a very remote location in the waters off the coast of Tierra del Fuego certainly could be considered challenging. In this case study, the operator successfully constructed extended reach wells through low fracture gradients under the previously described harsh environment.

Attempting to circulate long columns of cement slurry when constructing extended reach drilling (ERD) wells under these conditions stretches the limits of current technology. Nowhere else in the world has success required more preplanning and implementation of the latest technologies. Failure to achieve a seal could have a large impact on the cost of drilling these wells and the operator's ability to effectively produce the new field. In addition to the cost of the required remedial work, which is easy to quantify, additional costs can be accrued from delays in production delivery, which are harder to quantify.

This paper presents case histories from Tierra del Fuego illustrating preplanning methodology, design strategies, and new technology implementations required to make this exploration project a success.
Time-Based Real-Time-Drilling-Operations Excellence Delivered
Authors: Strathman Michael , Elley Dave , Meirerhoefer Norbert
Published: December 2007

E&P companies have managed drilling operations from central locations for sometime. However, operators remain limited in their ability to use the data to develop better procedures for drilling complex wells, to compare data across various vendors working on the same well, and from being able to look at the well data in time not just in depth. Realtime drilling solutions from major drilling companies focus on data they capture, are based on depth not time, and do not lend themselves to comparison's between wells.

Statoil examined this problem and has worked with Aspen Technology to develop and implement a time-based drilling solution. This solution is used in parallel with the depth based systems provided by its drilling contactors. Data is captured from the well site in real time, stored in a historian, and made available in vertical trends through time. The solution is configurable by the operator to look at different data sets side by side in time sequence. It enables closer collaboration between the geoscience, petroleum and drilling engineers working on a well. The solution leverages the data standard of WITSML to ensure compatibility between vendors.

Statoil has reduced the cost to access its data from wells, improved its ability to develop better drilling plans. Drilling is a critical, data intensive process and reliability and ease of use are essential. This system provides that reliability. Because it is reliable and real-time the decision making across disciplines can be brought to a common collaboration center where all well data is displayed and available.

This paper will present the business issues addressed the solution and benefits achieved.
Successful Application of Underbalanced Coiled-Tubing Drilling in Horizontal Short-Radius Re-Entry Well To Enhance Oil Production in Hassi Messaoud Field, Algeria
Authors: Amor Bachir Ben , Ferhat Ali , Messas Rafik , Arnone Maurizio , Stulberg Michael , Khan Rashid , Schoch Fritz , Fordyce Charles , Qutob Hani , Chopty James
Published: December 2007

Drilling in the Cambrian Reservoir, in the peripheral zone of Hassi Messaoud field, specifically the 1A, 1B and 1C zones (Figure 1) is a real challenge, basically due the petrophysical reservoir complexity, the low reservoir pressure, the extremely hard and abrasive sandstone and quartzite formation associated with numerous vertical and sub vertical fractures that connect the reservoir with deeper formations leading to major problems related with the salt saturated water production. Many of the vertical wells drilled in that zones have more than 30 years from completed and a large proportion of them have been shut in since being drilled.

Well E was the 5th re-entry well in the Sonatrach Coiled Tubing – Underbalanced Drilling campaign. A total of 372 m from KOP and 316 m from landing point were successfully drilled in a continuous underbalanced condition inside D1 formation. As a result, the well productivity while drilling, the Reservoir characterization and rate of penetration was significantly improved, compared with offset wells, due to the positive impacts of UBD operations.

The combination of Underbalanced and Coiled Tubing Drilling technologies has been proven to be a viable solution to successfully drill horizontal re-entry wells in mature fields where the reservoir pressure is adequate to induce underbalanced conditions using single phase or multiphase drilling fluid.

The experience in this field has validated the benefits of the combination of these technologies and has been attributed to the excellent balance between drilling cost and improved productivity. For example, the drilling cost in the short radius re-entry wells drilled with coiled tubing are highly reduced due to the elimination of pipe connection procedures, the increase in rate of penetration, the prevention of conventional drilling problems such as fluid circulation loses and related differential sticking events, the increase in the bit life and reduction in time and drilled distance to reach the profitable production level.

This paper describes the technical basis for the design and implementation of the Coiled Tubing Underbalanced Drilling project in Hassi Messaoud and highlights the operational key factors and challenges faced during this particular and successful application in Algeria.
Optimal Development Strategies to Different Scenarios of Reservoir Properties: Application to a Real Field
Authors: Salomão M. C. , Figueiredo F. P.
Published: December 2007

In petroleum industry, scarce information is available at the time of adopt the exploitation strategy, and the expected production profiles comprise a high level of uncertainty. Depending on the range of the uncertainty variables, the best decision may be to collect more information by drilling more wells, performing a new seismic acquisition or making long term tests. But, sometimes, the best way to protect the project is to assume an uncertainty-proof development strategy. These ideas were applied to help decision in two real cases, in Marlim Sul field, Campos Basin, Brazil. In the first case, the main uncertainty source is the quality of the flow transmissibility between producers and injectors wells. If that communication is restricted, the production decline is more accentuated and the best strategy would be to place the injectors nearer the producers, although the displaced oil is reduced. In order to elect the best strategy, we have compared two different plans containing different positions of injector wells, applied to three different scenarios of flow transmissibility. In the second case, we have a channeled reservoir, with an extensive fault in the middle, the transmissibility along which is unknown. In a scenario of good communication, the best strategy is to position the injectors on one side and the producers on the other side of the fault. But in scenarios of restricted communication, the best scheme could be to place injectors and producers on both sides of the fault. To make the best decision, we have used different plans, applied to different scenarios. The results demonstrate that, in both cases, the alternate plan has not the higher net present value (NPV) in the moderate scenario, but presents the higher expected monetary value (EMV), having also a lesser sensitivity to the reservoir uncertainties, being more protected to the risk. In both cases the original plan has been abandoned and the alternative plan started being implemented.
On Equation of State
Authors: Ahmed Tarek
Published: December 2007

To predict the phase and volumetric behavior of hydrocarbon mixtures by using an Equation of State; e.g. the Peng and Robinson Equation of State "PREOS", the critical properties in terms of the critical pressure "pc" and critical temperature "Tc" as well as the acentric factor "ω" must be given for each component present in the mixture including the plus-fraction. For pure compounds, the required properties are well-defined, but nearly all naturally occurring gas and crude oil fluids contain some heavy fractions that are not well defined and are not mixtures of discretely identified components. These heavy fractions often are lumped and called the "plus-fraction" (e.g. C7+ fraction). Adequately characterizing these undefined plus fractions in terms of their critical properties and acentric factors has long been a problem. Changing the characterization of the plus fraction can have a significant effect on the volumetric and phase behavior of a mixture predicted by the PREOS. The inaccuracy of any the cubic equation of state results from the following two apparent limitations:

improper procedure of determining coefficients a, b, and α for the plus fraction Equations of state treatment of hydrocarbon components with critical temperatures less than the system temperature (i.e. methane and nitrogen).

Numerous authors have suggested that the EOS is generally not predictive and extensive splitting of the C7+ fraction is often required when matching laboratory data.

This paper presents a practical approach for calculating the coefficients a, b, and α of the plus-fraction from its readily available measured physical properties in terms of molecular weight "M" and specific gravity "γ" with the objective of improving the predictive capability of equation of state. The predictive capability of the relationship is displayed by matching a set of laboratory data on several crude oil and gas-condensate systems. In addition; the performance of the proposed method was also compared with predictive PVT results as generated by using PVTSimTM software of Calsep. Additional comparisons are made by comparing the proposed modified PR EOS results with those of Coats and Smart4 regression methodology with PR EOS.

This study concludes that when the coefficients of the plus-fraction, i.e. a, b, and α, are determined based on the proposed methodology; splitting of the C7+ into a number of pseudo-components is essentially unnecessary.
Hydraulic Fracturing Using Heated Fluids Brings Success in High Pour Point Waxy Oil Reservoir in India
Authors: Shaoul Josef , Ross Michael , Spitzer Winston , Wheaton Stuart , Mayland Paul , Singh Arvinder Paul
Published: December 2007

Most existing production of waxy oils occurs from high permeability formations, and wax issues are mostly a problem in the production tubing or pipeline. Large reserves do also exist in low permeability formations that require hydraulic fracturing for economic production. Such a reservoir was recently discovered in Rajasthan (northwest India), overlying a more typical high permeability formation, both with high pour point waxy oil. Since a very large amount of oil-in-place is present in the low permeability formation, two fracturing campaigns were performed in two different horizons to assess the potential for successful well stimulation. The first fracturing campaign (on four wells) showed limited success. A study was performed to determine the reason for the failure, and significant changes were made for the 2nd campaign. This paper documents the 2nd campaign. This campaign featured the first successful use of heated fluids in India to stimulate a shallow, low permeability, massive oil reservoir containing high pour point waxy oil.
A Multiphase Flow Correlation for Low-Rate and Low-GLR Gas Wells
Authors: Vidal Manuel , Kusanovic Guido , Hoffmeister Carlos , Gilardone Carlos , Lervasi Juan , Canel Carlos
Published: December 2007

The analysis of alternatives of development of gas deposits and condensed is usually carried out by using the coupling between the balance of materials in predictive mode and the nodal analysis or also using numerical simulation models. In both cases it is required a suitable model of the multiphase flow behavior in vertical pipes in order to be able to predict with accuracy the flowrates the wells will produce through the different life stages of the reservoir.

The correlations for the multiphase flow, with which it is modeled the flow in vertical tubes, show a big dispersion of results in flowrates less than 50 km3std/d with gas – liquid relationships less than 10000 m3/m3. This area of low flowrates and low gas – liquid relationships is usually observed in the gas and condensed reservoirs final phase due to the decline in the production because of the fall of the static pressure and the fall of the gas – liquid relationship and the increase of the water cut.

Consequently, the dispersion in the correlations generates important differences in the production forecasts, with the associated high economic impact, because the pressures for abandonment of the wells are very different according to the multiphase correlation used.

In this work we show an exhaustive statistical analysis of the behavior of the multiphase flow correlations in vertical tubes, contrasted with measurements of pressure gradients in wells, in the majority of the cases within the ranges of flowrates and gas – liquid relationships mentioned in the previous paragraph.

From the results of this analysis, it is developed a new correlation of multiphase flow for gas – condensed – water systems that allows predicting the pressure gradients in vertical tubes within the reasonable error ranges.

We show the methodology used for the development of the correlation and the statistical analysis of the results of the application of it based on the data from the studied cases.
Strategic Plan of SCADA, Automation and Control Systems for Business Unit Las Heras
Authors: Diaz Gonzalo , Gonzalez Del Port Jorge
Published: December 2007

The main purpose of this work is to show the strategic plan regarding to Automation & Control Systems built for the Telesupervision of the oil fields and upstream of the Business Unit Las Heras (UELH).

This work arose from the necessity of developing a system that must enter into a process of technology renovation in the Telesupervision system of the Area. This paper also shows the description of each one of the components of the new system to be put into operation in the years to come, the process of transition from the existing system and the migration to the new technologies to be applied.

The necessity of a new, integral and reliable System arose from the requirements of a trusted, real-time data delivery and safety-oriented System. This integral system hast to cover the demands of the Production Area, in two main aspects: solid data delivery of the oil fields and the capacity of interconnection between other monitoring software systems used to develop production strategies.

Given this, for the principal actors of the Engineering Department of the UELH, a whole new philosophy and perspective got into account. They must merge the Production Area needs and build the architecture based on new, fast and reliable technologies in order to improve the communications and control system.

The strategic plan was then organised in the development of a instrumentation and control standard for the main facilities in the Upstream Production Area for the Oil&Gas industry. These are: Batteries and Auxiliary Collectors, Satellite Water-Injectors, Water Injection Plants, Oil Treating and Dehydration Plants, Gas Compressors. In addition, above this, a new –standardized SCADA System and a fast, improved and redundant Communication and Networking System.
Applications of Electric Logs and Geomechanical Models to Optimize Drilling and Well Completions in the Burgos Basin
Authors: Monroy-Ayala Norberto , Hernández-Patiño Antonio , Celis Eduardo , Sheridan Judith , Ward Chris , Torne Juan Pablo
Published: December 2007

Electric logs and borehole imaging were used to build a geomechanical model to predict wellbore instability during drilling and to optimize casing designs and completions to control sand production in the Burgos Basin.

This paper describes how geomechanical models can explain several problems in drilling and completion during the development of some of the fields in Northern Mexico. The total stress tensor model, the pore pressure model, and the mechanical properties model are discussed. Validation of the model is a critical step before it can be applied to design new wells.

The geomechanical model was used to design a new well and to optimize drilling, completion, and production techniques for the reservoir. The model was used to optimize the placement and orientation of perforations, evaluate proposed hydraulic fracturing designs, and select the critical draw-down to produce a well. Actual drilling, completion, and production events for the new well were analyzed, and conclusions about how the geomechanical model supported the complete design are also included in this paper.
Predictive Data-Mining Technologies for Oil-Production Prediction in Petroleum Reservoir
Authors: da Silva L. C. F. , Portella R. C. M. , Emerick A. A. , Ebecken N. F. F.
Published: December 2007

This paper describes the use of neural network approach as a time series tool to represent the field as a black box, to make predictions of fluid production.

The classical tools available and widely used are numerical reservoir simulation and analytical methods, like decline analysis and material balance. These classical methods are not problem-free. Although the analytical methods are easy to use, sometimes they do not provide good results in several situations (changes of injection rates, opening or closing production intervals, etc.). On the other hand, numerical reservoir simulation, which usually gives better results, it is a very complex tool that may require several months to build a flow model of a field, especially when the field to be modeled is a mature field with several years of production history. Besides that, the flow models require an update from time to time, usually once a year, that also requires a lot specialized work for a long time.

Neural network techniques were applied in two sets of data from real fields to evaluate the possibilities of using this technology in this specific problem using only a small amount of production data as input for the predictive method. For that situation a short term prediction was performed. A synthetic reservoir was also used to generate a long production history in order to test how the technique would behave in a long term production forecast. For both cases, a comparison with classical methods is presented. Neural network architecture design and optimization techniques are also discussed. Results showed that the neural network models performed better than the decline curve analysis in all cases.
Overview of H2S Souring Cases in Argentina Reservoirs: Origin and Mitigation Scenarios
Authors: Cavallaro A. N. , Alberdi M. I. , Galliano G. R.
Published: December 2007

H2S is an element toxic to life that can be associated to natural gas, oil and production water. It is very dangerous to operational staff and causes corrosion-cracking and pitting of steels-, especially when it is associated to water.

The petroleum fields can early show H2S associated to the original fluids or it can appear later in mature stages. The generation mechanisms of H2S have been classified as biotic (biological sources) or abiotic (geological or geochemical sources). The first one is related to the development of Sulphate Reducing Bacteria (SRB) in reservoirs. The best-known reason is the injection of SRB with seawater in combination with nutrients of formation waters. Abiotic mechanisms involve only chemical reactions between organic, inorganic phases and water. Temperature and pressure are critical parameters: themochemical sulphate reduction (TSR), hydrolysis of metallic sulfhurs, cracking of organic compounds, cracking of kerogen and volcanogenic sources are examples of abiotic mechanisms.

According to this classification, most of the H2S souring cases in Argentina can be, on some level, related to the development of SRB, but alternative sources have been studied to explain the new reports of H2S on fields with high contents of original H2S. This paper classified the fields in Argentina with H2S in three categories;

The oilfields that show progressive H2S souring after a secondary recovery project. SRB were introduced with the injection of foreign waters and three examples are shown: Chihuido Lomitas, Barrancas and Las Heras-Cerro Grande (Cases A, B, C). A second group of oilfields report low concentrations of H2S still in primary production without previous history of H2S. SRB could be indigenous or introduced with drillings fluids. El Alba and Grimbeek fields are presented in this paper as Case D. A third group of fields show medium and high values of original H2S (>2000 ppmv) since the firsts development activities. A possible contribution of abiotic H2S sources is now considered. Some fields in the Neuquen area could show a mixture of mechanisms (biotic and abiotic). The characteristics of these fields are summarized in Case E.

All reservoirs require H2S simulation to design surface pipelines and environment management. However, according to the origin of the H2S, a variety of mitigation and control technologies have already been implemented in these fields.

This paper summarizes the three groups of fields in Argentina that produce H2S, altogether with their water-chemistry, evidences of H2S origin, associated problems and control practices.
Numerical Simulation of Density-Driven Natural Convection in Porous Media with Application for CO2 Injection Projects
Authors: Farajzadeh R. , Salimi H. , Zitha P. L. J. , Bruning J.
Published: December 2007

In this paper we investigate the mass transfer of CO2 injected into a homogenous (sub)-surface porous formation saturated with a liquid. In almost all cases of practical interest CO2 is present on top of the liquid. Therefore, we perform our analysis to a porous medium that is impermeable from sides and that is exposed to CO2 at the top. For this configuration density-driven natural convection enhances the mass transfer rate of CO2 into the initially stagnant liquid. The analysis is done numerically using mass and momentum conservation laws and diffusion of CO2 into the liquid. The effects of aspect ratio and the Rayleigh number, which is dependent on the characteristics of the porous medium and fluid properties, are studied. This configuration leads to an unstable flow process. Numerical computations do not show natural convection effects for homogeneous initial conditions. Therefore a sinusoidal perturbation is added for the initial top boundary condition. It is found that the mass transfer increases and concentration front moves faster with increasing Rayleigh number. The results of this paper have implications in enhanced oil recovery and CO2 sequestration in aquifers.
Upscaling in Fractured Reservoirs Using Homogenization
Authors: Zanganeh M. Namdar , Salimi H. , Bruining J.
Published: December 2007

Homogenization is a powerful upscaling technique, which has been successfully applied to a variety of problems of interest, such as reactive contaminant transport and two phase flow in layered and fractured media. It has several advantages over other upscaling techniques, such as REV averaging. It does not use intuitive closure equations and it explicitly shows the dependence of the upscaled equations on the characteristic dimensionless numbers of interest. It is based on a well defined procedure, which precludes ad hoc assumptions. A disadvantage is that the underlying assumptions of this procedure have not received sufficient attention in the existing literature.

This paper examines the existing homogenization models for two phase flow in fractured media with the purpose to clarify the underlying physical assumptions. We give the derivation for a specific case for which we discuss the validity of the assumptions. Finally, we discuss an example to show the applicability of the ensuing model equations.
The Challenges of Developing a Deep Offshore Heavy-Oil Field in Campos Basin
Authors: Figueiredo F. P. , Branco C. C. M. , Prais F. , Salomão M. C. , Mezzomo C. C.
Published: December 2007

Deep offshore oil production demands very high investments (CAPEX) so its development must rely on a careful planning. This frequently takes place in a setting with very limited amount of information due to high costs of appraisal operations. The figure becomes even more complicated when heavy oils are the target: low energy reservoirs require water flooding which, in turn, reflects in low recoveries and excessive water handling, not to mention other production problems.

This paper highlights different simulation studies that have been performed in order to set up an economical development plan for a 16 API 1700m water depth oil reservoir offshore Campos Basin. The main reservoir consists of a high thickness turbidite channel crossed by a N-S fault whose hydraulic conductivity is the main uncertainty. Vertically the reservoir is composed of three zones, where the upper one has a gas cap partially in contact with the two bottom ones. These structural complexities required a detailed study for positioning injectors and horizontal producers based on a decision tree analysis. The impact of other uncertainty variables was also identified and studied: horizontal permeability, vertical to horizontal permeability ratio, water-oil relative permeability and productivity index. Particular attention was given to the injectivity decline due to the planned produced water re-injection. Vertical and horizontal injection wells performances were compared in a scenario under strict geomechanical restrictions. The simulation model was also used to evaluate the possibility of developing marginal areas close to the main reservoir body.

The study leaded to a robust strategy for the water injection scheme. Risk and marginal reservoir analysis helped the decision of the features of the future production system in terms of oil and liquid processing capacity and adoption of some flexibility to make feasible the future development of marginal areas.
Streamline-Based Simulator for Unstructured Grids
Authors: Pomata M. , Menéndez A. , Valle J.
Published: December 2007

Oil recovery operations are strongly conditioned by a series of complex phenomena that take place in the reservoir. Presently, it is common to use numerical modeling tools for the oilfield development.

In this paper we present the first implementation step of a streamline-based simulator for unstructured grids. In this stage, we focus on a 2D incompressible flow model. Streamline flow simulation has been extensively used for the past ten years, and it is now used as an effective and complementary tool to more traditional flow modeling approaches, such as finite differences.

Streamline-based simulation is suitable for large, geologically complex and heterogeneous systems, where fluid flow is dictated by well rates, rock properties, fluid mobility and gravity. Capillary effects and expansion-dominated systems are not modeled correctly using streamlines.

The mathematical model is based on the mass conservation of the three-phase system.

The basic hypothesis, as well as the mathematical model on which the streamline-based simulator stand, are presented in some detail.

We use the finite volume scheme as the numerical method for the discretization of the differential equations. Trinodal triangular elements are used. The pressure equation formulation is space centered with an upstream formulation for the phases mobilities and is solved using a direct skyline solver2. The 1D saturation equation is discretized using an explicit finite difference scheme in time and an upstream formulation in space.

The results obtained by our streamline-based simulator are compared with known analytical solutions (such as Buckley-Leverett flow) and with our previous full implicit black oil simulator. Good quantitative agreement is obtained.
Validating the Use of Experimental Design Techniques in Exploratory Evaluations
Authors: Amorim T. , Moczydlower B.
Published: December 2007

This work presents a validation of the use of Experimental Design (ED) techniques in exploratory evaluations. The results generated by a commercial software, which uses ED techniques combined with the Monte Carlo method, have been compared with 10,000 equivalent actual flow simulations. Several oil and gas real reservoirs were studied. The static and dynamic variables were selected from real prospect studies, as well as their respective range of variation. For each case studied, the commercial software planned a small number of flow simulations to run, applying different ED techniques. Based on the simulation results, a proxy model was generated using the Response Surface Method (RSM). Making use of this proxy model, it was possible to quickly simulate 10,000 experiments and to perform statistics calculations with the Monte Carlo method.

In order to verify the quality of the proxy, 10,000 simulation files were generated, with the exact same combinations of parameters used in the Monte Carlo method. A script was written to run automatically all the files and to register their results. Besides comparing the statistics generated by these two methodologies, it was possible to compare the actual results of each one of the 10,000 simulations.

The results indicate that the quadratic technique is the one with the best cost-benefit ratio and suggest that the proposed methodology generates reliable results in most cases. This reliability decreases when there are complexities in the flow model, such as well and group controls, water and/or gas reinjection, etc. However, results show that the range of possible results to be emulated by the proxy model is the most influential parameter in the quality of the results generated by it.

The quality of the risk analysis performed with these ED techniques is obviously influenced by the ability of the proxy model to emulate the flow simulator response. The efficiency of different ED techniques, in different reservoirs, was analyzed and the reliability and limitations of this evaluation methodology has been accessed.
A Quadrilateral Element-Based Finite-Volume Formulation for the Simulation of Complex Reservoirs
Authors: Hurtado F. S. V. , Maliska C. R. , da Silva A. F. C. , Cordazzo J.
Published: December 2007

In this work is presented a numerical formulation for reservoir simulation in which the element-based finite-volume method (EbFVM) is applied to the discretization of the differential equations that describe macroscopic multiphase flow in petroleum reservoirs. The spatial discretization is performed by means of quadrilateral unstructured grids, which are adequate for representing two-dimensional domains of any complexity in an accurate and efficient manner. Although mass conservation is enforced over polygonal control volumes constructed in a vertex-centered fashion, media properties are assigned to the primal-grid quadrilateral elements. In this way, non-homogeneous full tensor permeabilities can be handled straightforwardly. Piecewise bilinear shape functions are used for approximating the main variables in the differential equations. The exception is the advection term in the saturation equation, which is approximated by means of a twodimensional positivity-preserving upwind scheme. Numerical results without noticeable grid orientation effects were obtained using this type of approximation, even for the most adverse cases with high mobility ratios and piston-type displacements. Additionally, some simple problems with known analytical solution were solved in order to assess the accuracy of the method. We show that the approximation of the pressure field is second-order even for non-homogeneous anisotropic media. Finally, the ability for solving fluid displacements in faulted reservoirs of complex geometry was tested with a synthetic problem.
Quebrache–A Natural CO2 Reservoir: A New Source for EOR Projects in Mexico
Authors: Muro Heron Gachuz , Campos Sergio Berumen , Alcazar Cancino Luis O. , Rodríguez Pimentel José A.
Published: December 2007

CO2 injection is one of the most efficient methods used to improve oil recovery, and, as world statistics shows, its use has increased recently. Under a high crude oil price scenario, field applications of enhanced oil recovery (EOR) processes are becoming economic in today's environment. The natural CO2 sources come to be an excellent opportunity because of its low cost. Since 60 years ago, 2500 km2 of carbonate formations containing CO2 were discovered in North of Mexico.

The Quebrache region contains several occurrences of natural CO2 that have been discovered during exploration of oil fields. The CO2 that has been naturally trapped in carbonate formations in this region is present in concentrations that can exceed 90% purity. Due to the high concentrations of CO2, some wells were shut-in 60 years ago, others, have been developed for CO2 production intended for industrial uses and some others as a source of gas lift operations in nearby heavy oil fields.

Recently, a plan of acquisition of information and studies to evaluate the CO2 proven reserves has been designed. In addition, analysis of wells deliverability of these natural CO2 reservoirs, located in the southwestern portion of Tampico, has been carried out. In order to understand better this field, a geological model was built and its dynamic behavior and potential was examined through several well tests. Results of the interpretation of these tests showed excellent results associated with a reservoir of good permeability, high conductivity, large drainage radius, etc. According to the geology of this region and the geochemical signatures observed, the CO2 of Quebrache field has an inorganic origin.

This paper discusses the evaluation of potential supply of CO2 of Quebrache reservoirs for EOR projects in the North of Mexico. The main region studied contains estimated proven reserves of 1.9 Tscf of CO2; however, this volume could be extended to larger amounts associated to areas under study. The CO2 from Quebrache field could be the beginning of a new era of EOR projects in Mexico. A field example of potential EOR application in a mature oil field is shown.
Simplifying the People Factor in the Technology Equation: Change Management That Works
Authors: Berger Tina
Published: December 2007

Today's technical workforce is being asked to adopt new technologies, tools, and processes at an unprecedented rate. These changes are being implemented in order to improve the speed and quality of critical decisions, to address the increasing technical complexity of accessing reserves, and to allow fewer experts to support a greater number projects. Examples include Real-Time Operations technologies, Advanced Collaboration Environments, Directional Drilling Tools, 3D Visualization Technologies, and Real-Time Production Reporting.

This paper provides a summary of the key challenges associated with implementing and sustaining technology adoption within today's bustling energy organizations. The paper also provides an overview of key considerations regarding change leadership, generational differences, and typically-encountered resource issues. Best practices are highlighted and examples are provided.