bluuebunny/crossref_metadata_2025 huggingface dataset:
The Frade Development Asset: How Robust Project Management Drove the Asset From Economically Marginal to One Company's Cornerstone Development Project in Brazil
Authors: Bergeron J. M. , Parvez N.
Published: December 2007

The Frade project is Chevron's recently announced (June, 2006) deepwater heavy-oil sanctioned development project requiring a capital investment of approximately $2.5B. The development project is located in the northern Campos Basin juxtaposed to Petrobras's Albacore Leste and Roncador developments. First oil for Frade is scheduled for Q1 2009. Frade, being a deep water heavy oil development project, has historically been both technically and economically challenged. The inherent subsurface and surface complexities alone might have shelved the development of this asset – particularly in the early evaluation period. Moreover, the fiscal and political landscape in Brazil has proven to be less than predictable further providing additional obstacles to project success.

After merging with Texaco in 2001, Chevron realized that a different approach would be required to assess the true value of the Frade asset, and initiated a systematic and standardized asset valuation process for Frade as part of its worldwide portfolio management exercise.

This paper will review the manner in which the development concept evolved from full-field platform to phased subsea as a consequence of employing tried and true business and technical processes that integrate G&G, reservoir engineering, drilling, decision analyses, and surface facilities. In particular, we will address one of the principle elements of Chevron's asset evaluation process - the Peer Assist - as it was employed at Frade along with resulting workplan and results.

The paper is a case history describing the progression of the Frade project from a marginally economic asset to the foundation of Chevron's deepwater Brazil portfolio. The focus of the paper will describe the approach used by the Frade Project Team to facilitate better decision making at critical stages of project development. Key elements of the approach involve: A multidisciplinary collocated team to ensure cross functional alignmentPeer Assist engagement meetings that involve cross-functional technical staff to review project uncertainty and recommend workplans to address these uncertaintiesIncorporating uncertainty in asset evaluation and development cost modeling/probabilistic analysis so as to ensure acceptable project economicsApplication of probabilistic Decision AnalysisA structured Decision Process involving cross-functional business and technical teams

Finally, we will show how robust Front End Loading (FEL) is critical to drive high quality investment decisions – specifically in marginally economic projects similar to Frade.
Beyond the Frac: Using the Fracture Process as the Delivery System for Production Chemicals Designed to Perform for Prolonged Periods of Time
Authors: Szymczak Steve , Brock Gene , Brown J. Mike , Daulton Dan , Ward Brian
Published: December 2007

It is a well-accepted practice to add production chemicals to a formation through a squeeze process. These are designed to place chemical in the near well area and treat the fluid for scale, paraffin, salt, etc. Now, frac-fluid approved chemicals are added to the fracture in order to place products deeper in the formation. In addition, concentrated solid versions of some chemicals have been formulated to provide prolonged treatment. This paper deals with the application of three production chemicals through the fracture fluid process. These chemicals were used to address the problems of scale deposition, bacteria-related corrosion and oxygen induced corrosion.

Fracture fluids are complex blends of chemicals designed to perform specific purposes in a specific order during the fracturing process. The addition of non-frac chemicals adds another level of complexity to the formulation and compatibility processes. Thus, it was necessary to limit the scope of production chemical choices and to seek out the most robust products.

To date the following types of production chemicals have been added to a variety of fracture fluids: scale inhibitors, salt inhibitors, oxygen scavengers, biocides, asphaltene dispersants and relative permeability modifiers. Gas hydrate inhibitors and paraffin inhibitors, although not yet applied, have been tested and approved for compatibility. In the future the authors hope to report on the outcome of fracturing and chemical programs that addressed the problems that required the use of these chemistries.

The significance of this new area of chemical application falls into two levels. For a land or shallow water well where intervention costs are a major issue then the choice to add production chemicals to the fracture depends on the severity of expected treatment problems, the remoteness of the well and other operational and economic drivers. However, in the case of a deep-water well the application of key production chemicals applied during the initial stimulation could make the difference between a highly profitable well and a well that sees a production decline and requires an expensive intervention.
Effect of the Elastic Constants on the Pressure Behavior of Vertical Wells
Authors: Escobar Freddy Humberto , Munoz Oscar Armando , Brinez Diego Fernando , Guzman Julio Cesar , Cantillo Jose Humberto
Published: December 2007

Everyday, it is more frequent and common to adequately know the dynamical behavior of stress and strain sensitive formations and to improve their geomechanical characterization, as well. For this purpose, a coupled simulator of fluid flow and rock deformation was used in this study to investigate the impact of the elastic constants of the rocks during a well pressure test. The results were compared with those obtained for a reservoir with average properties in which the geomechanical effects were neglected.

The numerical experiments were focused on simulating drawdown tests for four different scenarios as follows: a standard case without geomechanical effects, two cases with isotropic initial state of stress and two cases with anisotropic stress. For interpretation and comparison purposes, we utilized the TDS technique to determine the reservoir parameters of the simulated pressure data. The results allow us to visualize that Young's modulus causes a pronounced effect on the pressure test during pseudosteady-state flow which leads to a wrong estimation of reservoir drainage area; a range of values were established above which its variation does not cause important effects. On the other hand, it was found that variations of Poisson's ratio are not significant since they fit in a small range of the values customary reported in the literature.
Polymer Flooding: A Sustainable Enhanced Oil Recovery in the Current Scenario
Authors: da Silva Ivonete P. Gonzalez , de Melo Maria Aparecida , Luvizotto Jose Marcelo , Lucas Elizabete F.
Published: December 2007

This paper presents a simplified economical analysis of PETROBRAS’ experience with the pilot project for polymer mobility control in the Carmópolis field, and an evaluation of the world and Brazilian current scenario of this technology.

The positive results of this pilot and the new world scenario of the oil industry, shown here, assure great potential of this technology, especially in a time marked by a rising oil prices and growing environmental and social conscience.

The pilot project was aimed firstly to evaluate the fit of the polymer technology to Carmopólis field, considering the particular characteristics of the field regarding rock heterogeneities, oil type, water salinity, temperature, pressure, etc. A second goal was to obtain know-how in all the project phases like lab tests, design and operation in field scale and, finally, technical and economical analysis as a function of the additional oil recovered and the direct investment. This economic analysis is a starting point for more comprehensive economical evaluations.

This economic evaluation closed the sequence and will be important to the possible future unfolds. This evaluation was done with a special criteria because of the operational typical difficulties of this kind of project. All the investment is justified by the fact of polymer injection to be, according the literature, the easiest application and one of the lowest cost of the incremental oil and besides, the onshore experience is the first step for the future offshore field application.

This experience demonstrated that the injection process of polymer for mobility control is efficient even for heterogeneous reservoirs as Carmópolis field, and still, in a sustainable way, in other words, with increase of the oil production and reduction of the use of the water and consequentially of the water produced, and of the costs and of the environmental problems associated to this water, in agreement with the new world partner-environmental conscience.
Novel Technology Replaces Perforating and Improves Efficiency During Multiple Layer Fracturing Operations
Authors: Rytlewski G. , Lima J. , Dolan B.
Published: December 2007

A new method of completing multiple layer wells has been successfully tested in the Piceance basin for Petrogulf Corporation. This new method placed sliding sleeve valves in the casing string and completed the well with normal cementing operations. The sliding sleeves were opened one at a time to fracture layers independently without perforating.

The valves have a unique design feature which allows an unlimited number of valves to be placed in a single well without incremental reductions to the ID, thus allowing normal cementing operations. A control line is connected to sequential valves. When the bottom valve opens, the control line becomes pressurized and transfers this pressure to a piston in the valve immediately above. This piston squeezes a C-ring and makes the ID smaller. At the end of the fracture treatment to the lower valve, a dart is dropped during the flushing operation. This dart lands on the C-ring and seals the bore inside the sliding sleeve. Pressure is then increased until the next valve is pumped open. When this valve opens, the next control line is pressurized, squeezing the next C-ring.

The main feasibility issue with this cemented sliding sleeve concept was the possibility of high fracture initiation pressure through the cement and into the formation without perforated holes. Significant laboratory testing was conducted that predicted fracture initiation pressure to be near openhole fracture initiation pressure. To confirm the laboratory testing, Petrogulf agreed to place two of these casing valves in a well in the Piceance basin to measure the fracture initiation pressure and test the functionality of the valves.
Optimizing Reservoir Permeability to Hydrocarbons With Microsolution Technologies
Authors: Gwartney Gary , Stephen Mark , Leeds C. Monty , Rea Tony
Published: December 2007

The focus of this paper is to discuss the importance of controlling multiple phase interfacial tension between all solids, liquids and gas phases associated with the drilling, completion and maintenance of wells. Particular emphasis will be placed on mature reservoirs, low pressure reservoirs, under saturated reservoirs, low perm reservoirs and their relative hydrocarbon production potential sensitivities associated with the interactions between the fluids and chemicals introduced during the various phases of the life of the well. Supporting laboratory studies and field case histories will be included.

Optimizing reservoir potential in mature, low pressure, under saturated and low perm reservoir environments requires a pro-active engineering design for the well construction and maintenance processes. The intermediate bridge technology between the reservoir and the mechanical equipment throughout the wells existence are the fluids employed to drill, cement, complete, workover and stimulate the well. These fluids and components therein are the primary bridge technologies for enhancing mechanical performance during the well construction process. More importantly these fluids are the primary foreign contact medium with the reservoir and therefore are secondary only to the reservoir quality in defining production potential.

Fluid and chemical selections are therefore dependent upon the rock and insitu fluid characteristics of not only the reservoir but all exposed formations during the drilling process. In all cases, fluid selection should focus on limiting the transference of free fluid from the bulk fluid phase to the reservoir, controlling highly mobile fluid invasion and optimizing surface forces between the rock, fluids and gases associated with the imbibition and invasion processes. Controlling the negative aspects of these interactions with micro-solution technologies minimizes filtercake lift off pressures, optimizes flow back of imbibed and invaded fluids during the drilling and completion processes and minimizes phase trapping. Employing micro-solution technologies in the workover processes improves remediating fluid efficiencies, idealizes the reservoirs permeability to hydrocarbons and the reservoirs production potential.
Surface Facilities Development for Mature Fields
Authors: Morales Rafael , Navarro Jorge
Published: December 2007

This work shows the main considerations adopted and proved successful for oilfield reactivation and production increase through the handling of very high gross production flow rate with high water/oil ratio. The execution strategy is focused on maximizing the production anticipation in the short-term by taking maximum advantage of the existing facilities and, in the mid- term, by developing facilities with new systems sized with flexibility and supplying them timely. All of these allowing to take advantage of the most suitable technologies existing in the market for handling, separation, treatment and disposition of high produced water flow rates, during the lifetime contract for each oilfield.

Examples of this approach are the study cases presented related to water injection for secondary recovery and disposal purposes. The knowledge obtained during the development and operation of a given mature field, has been adapted for its application in another field, and so on, considering particular features and different contractual terms, allowing PESA to success in very mature oilfields with apparently very restricted development opportunities.
Measuring CO2 in Coalbed Reservoirs
Authors: MacDonald Steven A.
Published: December 2007

Carbon Dioxide in aqueous coal reservoirs has import implications for a number of different applications. Detection and quantification of CO2 for sequestration, enhanced recovery of methane and/or naturally occurring CO2 can give valuable information that affects engineering decisions. In-situ Raman spectroscopy has been utilized to provide laboratory quality spectra of reservoir fluids in aqueous geological reservoirs. These spectra can be analyzed in real time to quantify the amounts of CO2 found in the reservoir. This gives the ability to monitor, spatially and temporally the amounts of CO2 in the reservoir.
New Oxidizing Breaker for Filter-Cake Removal at Low Temperature.
Authors: Albonico P. , Cobianco S. , Bianchi D. , D'Aloisio R.
Published: December 2007

The new generation of Drill-In Fluids have been developed to mitigate the potential of damage the producing formation and eliminate the need for post-completion cleanup. However depending on the reservoir features and the architecture selected for completing the well a significant reduction of the well productivity or injectivity can be caused by filtercake formation. The common approach is the application of breakers such as acids, strong oxidizers or enzymes. When an oxidizer treatment is the preferred option, high concentration solutions are usually applied at temperatures higher than 50-60 °C. Recently, the requirement of an effective oxidant breaker, as an alternative to acid, in low temperatures acid-sensitive reservoirs promoted an extensive research activity, which lead to a new cleanup treatment capable of effectively reducing the damage induced by the polymers which form the filtercake.

In this paper the performance at laboratory-scale of a new oxidizing agent is reported and some guidelines for its application including the possibility to delay its action are provided. The new breaker system consists of two components: a solution of hydrogen peroxide at a very low concentration (1-2% v/v) and an iron complex activator.

By coreflooding tests the effectiveness of this breaker to remove the external filtercake and the polymers, which entered the formation, was identified. Experimental results showed that this type of oxidants can degrade the polymers contained in the filtercake also at temperatures as low as 35°C, generating non-damaging by-products characterized by very low molecular weight. A delayed action of the breaker can be obtained by modifying the oxidizer concentration and the type of iron complex. Finally some results on the behaviour of the developed system in heavy brines including CaCl2 and CBr2 are presented.
Sand Control Robustness in a Deepwater Development: Case Histories From Girassol Field (Angola)
Authors: Petit G. , Foucault H. , Iqbal A.
Published: December 2007

Wells in the Girassol field, offshore Angola, are situated in very deep water and have being completed in unconsolidated sandy turbiditic reservoirs. Today in Girassol which includes also Jasmin reservoir, 29 wells have been completed and connected to production facilities and pressure maintenance is coming from 13 water injectors and 2 gas injectors. The completion strategies employed have included mainly stand alone screens in open hole and cased hole frac-packs.

A review of the design for both producers and injectors, along with the criteria related to the sand characteristics, and offshore implementation of the completions will be described.

Production strategy recommendations to minimize the sand risk during well start-up and ramp-up and also well steady-state production will be given.

This paper will provide an overview of the behavior of both sand control techniques after 5 years of production and injection. An in depth analysis of the different productivity/injectivity characteristics such as drawdown values applied and PLT observations during these 5 years allow us to draw some general recommendations for these types of sand control techniques when used in a similar geological environment. Impact of the measured drawdown values, on the sand control robustness will be described.
Well Productivity in North Sea Chalks Related to Completion and Hydraulic Fracture Stimulation Practices
Authors: Vos Bart , de Pater Hans , Cook Chris , Skjerven Tommy , Frederiksen Rene , Soerensen Carsten , Ormark Kjetil
Published: December 2007

The Joint Chalk Research (JCR) initiative is set up by a group of operators and partners in the Southern North Sea. The objective of the initiative is to increase the ultimate recovery in their respective chalk assets to 60%.

Analyzing the different production technology options used in the assets thus far was the next step in better understanding the different recovery increment options. The initial 4 year productivity from 4 assets was analyzed.

This paper presents the results of a study focused on increasing the understanding of productivity drivers using a database on well productivity related to different completions, stimulations and production options. The database contains 56 wells from 4 different assets and 750 acid and proppant treatments in 663 perforated intervals.

It was found that the absolute total production per interval is similar for all assets; however the drawdown applied in 1 asset is 4 times lower than the other assets.

The performance of the wells in most assets dropped strongly over time, except in the low drawdown asset. It was found that in addition to transient effects, it is likely that a decline in hydraulic fracture completion efficiency also contributes to this decrease in production performance.

The low drawdown asset has a much better normalized production performance than the other assets. Other factors might also influence this result, however, compelling evidence has been found that the much lower drawdown may cause the better performance over time.

The normalized recovery of propped fracced wells was better than the acid treated well in 2 of 3 assets using both stimulation types. The higher recovery of the propped treatments was mainly from better productivity over time compared with the acid fracture treatments. However, the initial productivity of the acid fractured well was much better, hence the economic balance could still tip to the acid treatments.

The analysis showed that, for all assets except one, there is a significant difference in the performance of acid fractured wells and propped fractured wells over time. Indications are that production declines are not only due to depletion, but also related to deterioration of the completion efficiency as a function of pressure drawdown and suboptimal efficiency of acid treatments. An extensive statistical analysis indicated a strong dependency on asset grouping, which hampers the extrapolation of experience from one asset to the others
Management of Steamflooding in Nine Spot With Fiber-Optic in Observation Wells
Authors: Silva M. F. , Izetti R. G. , Pinto H. L. C. Pereira , Santana A. P. S. C. , Couto I. R.
Published: December 2007

Castanhal is an onshore heavy oil field located in Sergipe-Alagoas basin northest of Brazil. It is a shallow unconsolidated sandstone reservoir. It has 75 wells where the average reservoir depth is 350m. The oil has high viscosity ranging from 1000 cp to 9000 cp and API gravity ranging from 10° to 16° API.

In early eighties, a small steam injection project was started in the field, but due to operational problems it was interrupted few years later. In that time the oil low prices make the field be practically abandoned: The production was carried on by very few wells without any fluid injection. In 2003, some successful experiences with frac pack and horizontal wells lead to a renewed interest in the field.

Geological and numerical studies have been accomplished and a permanent temperature monitoring technology was selected to improve the reservoir knowledge and validate the studies. Among the monitoring technologies available in the market DTS (Distributed Temperature Sensing) was selected. It allows a complete wellbore-temperature profile in few minutes if needed. In this case four observetion wells were equipped with an optical fiber placed along the entire length of the well. This paper will present a steamflooding pilot in a nine spot, with four temperature observation wells completed with frac pack to avoid sand production and DTS to improve the understanding of steam breakthrough in the producer wells and the steam path in the injection well. The information support better decision making to increase steam injection efficiency.
Generation of a Compositional Model to Simulate EOR Processes for the Complex Fluids System of the Carito-Mulata Field, Venezuela
Authors: Rodríguez F. , López G. L. , Bello J. , Skoreyko F
Published: December 2007

The Carito-Mulata field is located in eastern Venezuela. This field is ranked as a giant oil producer because of its 240,000 STB/D current oil production and its 6.5 MMMSTB original oil in place. It is possible to observe a significant compositional gradient from seventy-five fluid samples taken at different depths, over a column of fluids of approximately 4000 feet thick. This complex system changes from a gas condensate at the top to an under saturated black oil down the flank. The depth of the Gas-oil contact is estimated at 14,040 feet.

The Carito-Mulata field has been operated and characterized traditionally in four blocks (Central, West, North and South). The fundamental goal of this study is to establish a compositional model that can represent areally and vertically the complex fluid system using an Equation of State (EOS), which represents a big challenge considering the huge number of laboratory experiments. This EOS will be used for EOR simulations under gas and nitrogen injection processes.

The Peng-Robinson EOS was used to match the PVT experiments. Included in the matching parameters was the variation of the saturation pressure of the gas condensate due to nitrogen injection. A swelling test using black oil crude with the injection of gas condensate was also fitted, as well as stacked core miscible experiments of gas condensate displaced by nitrogen injection. Finally, a set of PVT tables were generated for the compositional numerical reservoir simulator.

The most important result that has been obtained of this project is to prove that a single Equation of State can model the complex thermodynamic behavior of three areas that were previously modeled as isolated. Considering that the field could be under nitrogen or natural gas injection, the Equation of State generated in this study will allow the numerical simulation to predict the impact of these processes on the ultimate hydrocarbon recovery.
Evaluation of Polymer Gel Diverters for a High-Temperature Field with Special Focus on the Formation Shape Factor—An Important Parameter for Enhancing Matrix Placement of Stimulation Chemicals
Authors: Stalker Robert , Butler Kristen , Graham Gordon , Wat Rex , Hauge Lars-Even , Wennberg Kjell Erik
Published: December 2007

Downhole scaling has long been recognized as causing significant damage to the near wellbore area of production wells. Furthermore complex heterogeneous wells, represent a significant challenge to ensuring effective placement and thereby protection along the entire length of the wells, as the injected chemicals (inhibitor or dissolver) naturally enter the higher permeability / lower pressure zones which may leave other zones untreated. Recent publications and field trials have demonstrated the benefits of using modified, lightly viscosified shear-thinning fluids to give more even placement of chemicals in such wells via bullheading. However, when large volumes of polymer gel are used the in situ fluid properties (viscosity) become critical as the fluid penetrates further into the formation. The in situ viscosity affects both the ability to place treatment chemicals into low permeability / high pressure zones and the post-job well clean up. Accurate prediction of the flow behaviour of these gels in porous media depends on the characterization of the physical properties of the reservoir zones, in particular the permeability, effective porosity and most importantly with shear thinning fluids – the formation shape factor. In this paper we present work investigating the suitability of such shear thinning fluids for non-damaging chemical interventions for an HPHT field. The paper will describe thermal stability tests and novel techniques developed to characterize non-Newtonian fluid behaviour under flow conditions between 120°C and 170°C. Results from bulk, coil and core tests will be included. The paper will also describe test protocols developed to investigate the parameters which could influence the formation shape factor. The work clearly demonstrates the significant impact that the shape factor has on diverting fluid into the low injectivity zones. The results will help achieve more even chemical placement and therefore improved scale protection/removal in the wellbore following treatments in complex wells.
Return Permeability Measurements—Proceed with Caution
Authors: Scott H. E. , Patey I. T. M. , Byrne M. T
Published: December 2007

Many papers have described different techniques and procedures for core floods that measure permeability "return permeability" to evaluate the magnitude of formation damage caused by fluid(s) used in operations (e.g. drilling muds, completion fluids). Often these measurements of permeability are used to make critical decisions for field development and well construction design.

This paper demonstrates with examples, the danger on having used only the permeability measurements to determine the extent of formation damage. Commonly, laboratory core flood tests will have used core cylinders cut to 1.5 inch diameter and short lengths (less then 4 inches) unavoidably limited by core retrieval. Short core samples may be useful if the depth of formation damage was restricted to within the core length, however would have been misleading if any damaging affects extend further than this. Formation damage effects commonly extend further than the length provided by short core samples. The extent of formation damage that occurred would not have been identified by using permeability but requires identification by performing comparative before and after test geological analysis techniques. Subsequently the extent of damage must be scaled from the laboratory to the field by experts in an attempt to extrapolate what those damaging effects have on field injection and/or production. Formation damage that caused alteration(s) to any core sample should be identified by comparing before and after test permeability measurements combined with all other analysis. The nature of any damage mechanism(s) would unlikely to have been identified by just some or any one measurement alone. Scanning Electron Microscopy (Dry and Cryogenic), Energy dispersive x-ray spectrometry (EDS), X-ray Diffraction Analysis and Thin Section Analysis should be incorporated to properly determine the nature and extent of formation damage.

The examples in this paper have never previously been published and they represent a continuing evolution in our understanding of formation damage measurements and mechanisms. Examples of mechanisms such as fines migration, fluid retention and mud body damage will be presented and discussed in terms of their potential impact on return permeability measurements.
In-Situ Stress Profiling in the Agency Draw Field, Utah
Authors: Rajappa Bharath , Conley John T.
Published: December 2007

This paper presents a method to calibrate the dipole sonic log data to the stress measurements derived from injection/ falloff tests. Generally stress data that is calculated from logs used for hydraulic fracture models is based on the poroelasticity model. It is often seen that independent stress tests and calculated log values differ significantly. In this paper, the strain-corrected method proposed by Blanton et al.1 is utilized to yield results that compare well with actual field data. The paper also compares methods used to calibrate stress data in the sand layers. Calibrated stress data is then used to develop a correlation between closure stress data and volume of shale for each well.

This work reviews and presents in-situ stress data gathered in various intervals in two wells in the Agency Draw field of the Uinta Basin in Uintah County, Utah. The primary targets for completion are multiple gas-productive sandstone intervals in the Blackhawk, Castlegate, Sego and Mesaverde formations. These low permeability (0.005-0.05 md) intervals cover a gross vertical extent of 1500-2000 feet. The wells in the field are completed with multiple fracture treatments, and then all perforated intervals are commingled in an effort to drain as many productive sandstone lenses as economically as possible.

Based on this correlation, stress data is input into pseudo-3D hydraulic fracture models to yield meaningful treatment designs. Post-treatment radioactive tracer survey data is then compared to the height growth predicted by the fracture model.

The paper details the importance of proper input data required for frac models and some of the pitfalls associated with incorrect assumptions.
Visualization of New Production Opportunities from Reservoir Characterization of Muri Field, Venezuela
Authors: Malavé A. , Carpio G. , Bolívar M. , Khan K. , Bello J.
Published: December 2007

The object of this work was Muri Field, which is located in eastern part of Venezuela. The expectations for this field were high at the beginning of the study. Firstly, the high oil quality of 30 °API; secondly, this field is located near another one under enhanced oil recovery processes with high production rate; and finally, the field has been inactive since 1.994.

This paper presents the use and results of a detailed Reservoir Characterization Model in the evaluation of opportunities for the drilling of new production wells. Applying conventional petroleum engineering methods, numerical simulation, and teamwork carried out the study.

Muri Field had a structural model generated from a 2D seismic interpretation. This model presented high simplicity and little coherence with the actual well information; being necessary to update it. This reservoir study considers a new structural model, based on a 3D seismic interpretation with a structural frame fitting actual data allowing optimizing the exploitation plans. The use of numerical simulation allowed strengthening the conventional reservoir engineering analyses and enhancing the production expectations for the area. The results are based on teamwork and the application of the available technology.

This new engineering study enabled to better evaluate the vertical communication in the field as well as the unification of four different reservoirs; all of them located in the geological formation with higher potential. As a consequence the official field limits were extended, and a lateral communication was established with a large producing field in north of Monagas State. The most relevant results were a two (2) fold increase in recoverable reserves and the evaluation of new exploitation scenarios. The locations of new producer wells were defined taking into account the new boundary area between Muri and the surrounding fields, to improve the final recovery.
Optimal Process for Design of Fracturing Treatments in a Naturally-Fractured Volcaniclastic Reservoir: A Case History in the Cupen Mahuida Field, Neuquen, Argentina
Authors: D'Huteau E. , Ceccarelli R. , Pereira M.
Published: December 2007

The declining reserves in conventional gas reservoirs imply that the oil and gas companies must consider the production of tight no-conventional gas reservoir.

The Cupén Mahuida Field is a naturally fractured reservoir composed of series of volcanic and volcaniclastic layers developed into a synrift stage at the Triassic in the Neuquén Basin. To obtain economical production all interesting layers had to be fractured. Therefore, we can assimilate that field to a tight gas, no-conventional reservoir.

Due to the huge difference in production between the different layers fractured in the existing wells, and due to the differences in behavior of the pressure during the treatments, it was decided to conduct a detailed analysis of each case. This included well construction, perforating strategy, geology, petrophysics, images log, minifracs and fracture treatments.

The results of the study showed two directions of work: First, necessity to modify the operations schedule; second, we needed to improve the definition of what are the layers candidates to stimulation. So operationally, we decided to change the casing size, the perforation scheme and we included as normal practice the use of proppant slugs to reduce the tortuosity effects we may see. The selection of candidate was improved by a better understanding of the formation thru an evaluation of outcrops that permitted to characterize the volcano clastic events and to correlate them with images, nuclear magnetic resonance logs and pressure measurements. With that information and the pressure response in the minifrac analysis we define the optimum size of treatment and the final proppant concentration.
An Experimentally Validated Wormhole Model for Self-Diverting and Conventional Acids in Carbonate Rocks under Radial Flow Conditions
Authors: Tardy Philippe M. J. , Lecerf Bruno , Christanti Yenny
Published: December 2007

Self-diverting acids are commonly used in matrix acidizing treatments of carbonate formations, not only to increase permeability by generating wormholes, as with conventional acids such as HCl, but also to self-divert into zones of lower injectivity, in the goal of optimizing zonal coverage. In this paper, a new model for wormhole propagation is proposed, which describes both stimulation and diversion processes.

A preliminary model is presented, which predicts wormhole propagation under radial-flow conditions for conventional acids. Then, a new set of parameters characterizing the reactive flow of self-diverting acids is developed, and the above model is extended to include self-diverting mechanisms. In particular, it is shown how the new parameters related to wormhole growth and those to diversion can be assessed from linear core-flood experiments and integrated into a new radial-flow model for field-scale prediction. Using this model, a new criterion is developed for diverter efficiency as a function of permeability contrast. Finally, the model is validated against radial flow experiments.

It is found that self-diverting acids are characterized by two new parameters which, when combined with the model for wormhole propagation, can be used to predict the performance of self-diverting acids, both in terms of wormhole penetration and in terms of zonal coverage. Some criteria are also developed to assess the diversion ability of acids.
Integrated Reservoir Management Enhances the Recovery in a Mature Field
Authors: Pérez L. E. , Gonzalez J. G. , Gómez V. , Lozano M. E. , Sarmiento L. E. , Vargas J. A.
Published: December 2007

In the current and future scenario of an increasing demand for hydrocarbons, many companies have oriented their efforts to maximize the recovery in mature fields. This paper presents the implementation and results of an integrated reservoir management strategy that allowed revitalizing a field, which was previously considered as a marginal and currently is one of the main assets of the company.

Yarigui-Cantagallo Field, Colombia, is a compartmentalized, varying-dip monocline, with three main tertiary reservoirs. The field was discovered in the 1940's and reached its production peak of 20,400 STB/day in 1962 after two aggressive drilling programs. A third drilling campaign in the 1980's had poor results and no additional wells were drilled. At 1999 production declined to 5,000 STB/day. In order to mitigate production decline, and maximize final recovery, integrated reservoir characterization including structural, stratigraphic, and petrophysical reinterpretation, geostatistic modeling, advanced production analysis, PVT and pressure reinterpretation, and reservoir simulation have been conducted.

An effective reservoir management has been implemented, including infill drilling, optimized well completion, hydraulic fracturing and production optimization. As a result, production levels had increased up to 13,000 STB/day and 40 MMSTB of reserves have been incorporated. Future implementation of a waterflooding project and additional infill program will incorporate 35 MMSTB of reserves.
Integrated Analysis for PCP Systems
Authors: Becerra Moreno Oscar , Mena Romero Maria Eugenia
Published: December 2007

One of the concerns that artificial lift engineers have to face when they are working with PCP systems is the lack of information about effective procedures for PCP diagnosis and optimization. Most of the information available is limited to explaining the importance of keeping the fluid level over the pump to avoid dry run. On the opposite side, there are some studies that explain the hydrodynamics of the pumps, and how some variables, like intake void fraction and fluid viscosity affect the pump performance.

However, there is no information available that may help field engineers understand the relationship between operational conditions and internal performance of the pump to know how each condition in the well could affect the pump, and how to determine and understand which condition is best for the system.

This paper introduces a new procedure to be used for understanding PCP's wells performance and therefore determine the best condition for system operation. Based on a set of simple mathematical models and patterns recognition techniques, this procedure is a useful tool to reduce the timing to analyze PCP systems and to automatically determine the best operational conditions in terms of production and performance.
Design and Surveillance of Development Projects through Specific Software Tools: Importance of Data Management in Mature and Complex Fields in the Golfo San Jorge Basin, Argentina
Authors: Mazzola Ricardo , Cano Frers Isabel , Baldassa Dario R. , Valle Jorge , Lacivita Alejandro , Ponce Carlos A. , Viola Alfredo F. , Laffitte Miguel A.
Published: December 2007

Proposal

Cerro Dragon is a mature Area located in the Argentine Republic, 90 km to the West of Comodoro Rivadavia and 1,900 km to the South of Buenos Aires, with a surface of 3,480 km2 and with 3,738 perforated wells.

Since its discovery in1958, and after a long history of production, a change of strategy on 1999 resulted in an important increase in Production and Reserves

Decision making at every level, such as people health, environment care, and strategic, organizational, structural, operative and technological planning, was key for the rebirth of this field.

The work is centered in how we handle the information, the entailment of the data bases and the use of systems we have built to contribute to maintain the production growth of the Cerro Dragón Asset.

Based on the field complexity we recognized that it was necessary to implement new tools that would allow us to make production and investments prognoses, integrating information from different sources, as well as to detect improvement opportunities.

The selected software tools allowed us to perform simulations and dynamically survey the projects. The information used came from geological, geophysical, physical production, interventions, measurements, and automation databases, among others. Some of them were developed during the 2 initial years (1999 – 2000).

The selected software tools additionally let us integrate the projects into the Long Term Plan, and Budget, taking advantage of the virtuous Circle of Plan-Do-Control-Learn.

A project simulation is solved in a period substantially shorter than the one it demands a conventional simulator, which is of great advantage at the time of analyzing different scenarios in an area where the structural complexity and the meager petrophysical information are important barriers at the time of making a study.

The control and daily pursuit of the Projects through these systems have favored substantially the fast decision making, the correct lease of resources and a better operative answer.

To complete the description of our Optimization options other tools and practices are described.
Pressure Evidence of Communication through a Canyon: Sedimentary, Structural, and Reservoir Management Aspects, Campos Basin, Brazil
Authors: Gangá Adriana O. , Braga Mário Sérgio S. , Silva Edilon R. , Bragança Glaucia H. , Maciel Walter B. , D'Oliveira Manoel M.S.
Published: December 2007

Caratinga giant oil field is located in the central part of Campos Basin, Southeast of Brazil, in water depths around 1,000 meters. The total reserve is around 290 MM boe in these turbidite sandstones, 78% of which are within the lower Oligocene Reservoir (CRT100) and 22% are within Oligocene/Miocene and Eocene/Paleocene reservoirs. The CRT100 is a turbidite submarine fan of maximum thickness of 40 m, that was further cut by a NW-SE, Lower Oligocene submarine canyon, that have segmented the reservoir in two blocks: North Block and South Block. This canyon was further filled by the Oligocene MRL600/700 and the Oligocene/Miocene MRL330 sandstones. These canyon-filling sandstones constitute the Central Block. The development strategy for this field included a Pilot Phase in which three producer wells, one in each block, produced to a FPSO. The history match of this production data did not consider connectivity between the North and South Blocks of the CRT100 reservoir; although, seismic data have suggested possible reservoirs connection through the Central Block. Despite these features were represented in the 3D reservoir modeling, the transmissibility multipliers used kept these connections closed. The definitive production system, with 12 producers and 8 injection wells, started in February of 2005. The extensive use of pressure down hole gauges and a dedicated reservoir team allowed the observation of very important new information about the reservoir hydraulic behavior. Among several other issues that have arisen, a good communication across the Canyon was confirmed, connecting the North and South Blocks. This effective hydraulic communication observed can be explained by the sand to sand juxtapositions between off-canyon and canyon-filling sandstones in some regions, whereas the low thickness reservoirs, associated to geological faults, can justify the fluid flow behavior in other regions. These issues have been considered in the flow simulation model. The results are showing an increment on the total recoverable oil, since some portions of the canyon sandstones that used to have a low recovery volume, are now being swept by the water flooding.
Experimental and Numerical Investigation of Proppant Placement in Hydraulic Fractures
Authors: Shokir Eissa M. El-M. , Al-Quraishi Abdulrahman A.
Published: December 2007

In hydraulic fracturing treatments, a fracture is initiated by rupturing the formation at high pressure by means of a fracturing fluid. Slurry, composed of propping material carrieby the fracturing fluid, is pumped into the induced fracture channel to prevent fracture closure when fluid pressure is released. Productivity improvement is mainly determined by the propped dimension of the fracture, which is controlled by proppant transport and proper proppant placement. Settling and convection (Density driven flow) are the controlling mechanisms of proppant placement. In this study, proppant transport and placement efficiency of four non-Newtonian fluids with controlled density differences was experimentally investigated and numerically simulated. Small glass model was used to simulate hydraulic fracture and parameters such as slurry volumetric injection rate, proppant concentration, and polymer type (rheological properties) were investigated.

It has been observed that small glass models easily and inexpensively simulated flow patterns in hydraulic fractures and the flow patterns observed are strikingly similar to those obtained by very large flow models used by previous investigators. Convection was observed to be significant flow mechanism even with small density contrast. As viscous to gravity ratio increases, due to increasing slurry injection rate or decreasing proppant concentration, convection settling decreases and proppant placement efficiency increases. Increasing non-Newtonian flow behaviour index (n) by using different types of polymers shows more gravity under-running and less proppant placement efficiency. Therefore, larger slurry volumes are needed to be injected in order to prop the entire fracture height. Experiments conducted were simulated and some of the simulated experiments were presented. The simulator quantitatively replicates the experimentally observed proppant placement and the match between the experimental and simulated results improves with the quality of fluids rheological data used in the simulation.