bluuebunny/crossref_metadata_2025 huggingface dataset:
Optimizing Gas Field Performance to Increase Gas Production Rates and Reserves
Authors: Stein M. H. , Venturini G. J. , Avasthi S. M.
Published: May 2009

Integrated asset modeling involves modeling performance from the reservoir to the completion, up the wellbore, through the facilities all the way to the plant inlet, and even up to the sales line. The integrated asset model consists of a coupling of different programs for each component of the operations, linked together through one computer program. The reservoir component may include reservoir simulation, or material balance. The well model represents inflow performance for the completion and wellbore hydraulics. For gas reservoirs, the reservoir and well models are typically coupled to a gas gathering system model, to predict pipeline pressure and temperature drop as well as model compression. A plant model can also be coupled to the gas gathering system model. The engineer adjusts the various models to match historical performance and then predicts performance for various operating scenarios. The goal for the engineer is to optimize performance within various facility and regulatory constraints, and determine how to maximize gas rates, reserves and profit.

This paper not only describes the integrated asset modeling process, but also describes case histories of how integrated asset modeling has been successfully applied to offshore and onshore gas reservoirs. A common objective in many of these case histories is to assess compression. Compression reduces bottom-hole flowing pressure and abandonment pressure, thereby increasing gas recovery factor. In one example, authors will show how the gas reservoirs of an entire offshore business unit in South America were tied together in a single integrated asset model. Each gas field was simultaneously optimized for the timing of compression to out run the aquifer and maximize gas recovery. Looping of a sub sea gas line was modeled to assure that the multiple gas field platforms did not bottleneck the sub sea gas lines.

Integrated asset modeling can also be used to manage daily gas reservoir operations. Integrated asset modeling programs have been linked to data automation systems. In one example, the integrated asset model calculated daily gravel pack erosion limits and the operator was able to maximize gas production rate without risking the sand control completion.
An Efficient Methodology of Production Strategy Optimization Based on Genetic Algorithms
Authors: De B. Nogueira P. , Schiozer D. J.
Published: May 2009

In this work a methodology of production strategy optimization, based on genetic algorithms (GA) is presented. The process aims to maximize the net present value (NPV) of the field and it is performed in terms of number and placement of wells. Independents optimization stages of quantity and placement of wells are alternated until the procedure convergence. The optimization stages of well placement are performed exclusively by a GA fitted with the goal of reducing the number of simulations needed for maximizing the NPV of the field. The optimization stage of quantity of wells may be carried out both by GA as an enumerative technique1. The choice is made, automatically, for the method that requires the lowest number of flow simulations.

The proposed methodology is applied in a selection process of production strategy. A case that aims to check the potential of performance of two production strategies is examined. The first production strategy is composed exclusively by vertical wells while the second one is composed exclusively by horizontal wells. The proposed methodology is used in the optimizations, subsidizing the selection process of the production strategy.

It is possible conclude that the methodology proposed gives a greater efficiency and reliability to optimization processes of production strategy. In addition, with the automated procedure, it is possible to evaluate a greater number of possibilities, increasing the scope of search for the best production strategy.
Experimental Study on In-Situ Combustion of Brazilian Heavy Oil
Authors: Chicuta A. M. , Trevisan O. V.
Published: May 2009

The present work refers to an experimental study on oil recovery by in-situ combustion. A specific apparatus holding a combustion tube of 100 cm in length and 6.9 cm internal diameter was designed and constructed for the study. Experimental tests were performed with a heavy oil of 12.8°API from a Brazilian onshore field. Plain air was injected at a constant rate of 3 SLPM, while the production pressure was set at 10 bar.

The main purpose of this study was to survey the influence of clay content in the reservoir rock with initial oil saturations ranging from 25 to 50%.

The results indicate that the in-situ combustion method is technically applicable to the rock-fluid system tested. Moreover, the tests were useful in providing the proper range of parameters for the oxidation reactions to occur. Clay has proved to play a key role on fuel deposition and, consequently, on propagation of the combustion front. In a clean sandpack medium, the combustion front was not self-sustained, while in presence of clay, in amount ranging from 4.5 to 10.0% mass fraction, sustainable combustion reactions were achieved. Front peak temperatures were recorded in the range of 457 – 501 °C, and for oil recovery factors were greater than 84%. From the set of data collected during the tests, results show combustion front velocities to span between 14.1 to 18.3 cm/h. Worth mentioning, upgradings of 3.2° to 8.4° API were observed in the produced oil.

The basic combustion parameters - fuel consumption, air requirement, air-fuel ratio, atomic H/C ratio, oxygen utilization - obtained during the experiments are favorable to the implementation of in-situ combustion and shall be used as a guide to the pilot project planned for the field.
A Parametric Study of Solvent Injection as a Recovery Method For Heavy Oil and Bitumen Reservoirs
Authors: Oliveira M. F. , Barillas J. L. M. , Mata W. , Dutra T. V.
Published: May 2009

There is still a large amount of natural resources in heavy oil reservoirs which can be explored using new methods. However, this enormous amount of hydrocarbon resources which are in these reservoirs may be explored with new concepts. The VAPEX process is a promising recovery method. The process consists in two horizontal wells, parallel between themselves, producer and injector, where vaporized solvent is injected with the objective of reducing the oil or bitumen viscosity. The purpose of this work is to examine how some important operational and reservoir parameters influence the VAPEX process, in the produced oil rates, in the cumulative produced oil and in the recovery factor. Parameters such as the spacing between wells, the injection pressure, and type of solvent, oil viscosity, residual water saturation and horizontal permeability are addressed in this study. The choice of solvent to be used in the process was the factor that most significantly influenced the process, allowing a greatest recovery factor of oil. The largest cumulative oil recovered was obtained for other parameters of significant influence as the longest distance between wells, increased horizontal permeability and lower injection pressure.
Innovative Completion Design and Systematic Approach Improves Operating Efficiency and Enhances Well Productivity
Authors: Omonze D. U. , Jackson M. R. , Osorio G. , Blanco E. R.
Published: May 2009

Hydraulic Fracturing has always been referred to as a multidisciplinary technique for delivering improved well productivity. In the BP exploration business operation, a successful hydraulic fracturing operation is a key requirement for cost-efficient well project delivery. With formation rocks requiring in excess of 18000 psi bottom-hole treating pressures, reservoirs with contrasting formation pressure regimes, complex stress profiles and the need for multi-zone commingled completions as business drivers, significant challenges arise in terms of down hole equipment limitations, increased complexity in completion installations, high project costs and diminished assurance of fracture pumping completion success.

An innovative well completion design and a thorough multidisciplinary planning strategy dramatically improved operating efficiency and successfully enhanced well productivity for the Guadalupe sands in BP Colombia operations. The system was implemented in the Floreña C6 well in the Piedemonte Field in Colombia. The completion installation technique also represented the "first of a kind" globally and sets the pace for the future completion work to be undertaken in the Piedemonte Field.

This paper comprehensively describes the total system approach implemented in various disciplines and the strategic planning applied to overcome critical obstacles in the well delivery process; optimizing project costs and creating increased assurance for the hydraulic fracturing operations resulting in a remarkable well performance.
In-Depth Analysis of Depth-Based Data Solves Severe Vibration Issues Drilling Interbedded Sand/Shale Sequences in 3D-Directional Well Profiles
Authors: Armour J. E. , Sankar R. , Thomson I. , Ramchune D. , Sas M.
Published: May 2009

Drilling the 17 ½-in. deviated hole sections in the Cashima field, southeast offshore Trinidad presented a number of distinctive challenges. Unexpected vibration was hindering real-time logging capability, reducing tool life and compromising drilling performance, resulting in increased well costs. The operator required a Rotary Steerable System (RSS) and PDC bit combination that could efficiently deliver all directional objectives on a repeatable basis, without compromising downhole tool integrity. The BHA needed to maximize ROP and minimize vibration while drilling through the abrasive interbedded sand/shale sequence, where UCS varies from 2,500psi to 4,000psi every one or two feet.

Initially, it appeared that RSS reliability was the main issue limiting performance improvement, due to the occurrence of failures of RSS components on three consecutive 17 ½-in. sections. An application-engineering group conducted an in-depth analysis to identify issues limiting drilling performance. Memory data was analyzed to fully understand the complex downhole dynamics critical to increasing directional PDC efficiency. This analysis led engineers to determine that the root cause of tool failure and performance deterioration was severe vibration, which resulted from the bit's inability to smoothly transition between the interbedded formations.

Improved PDC technology was required without any drastic change in operating parameters. Bit improvements included a more abrasion-resistant polished cutter, unique depth-of-cut control technology and the use of secondary stability features. From the implementation of a more stable PDC bit design, the following benefits were realized while drilling the 17 ½-in. sections of the last two wells: the targeted TD on each well was achieved in one run, with minimal intervention of vibration control methods and no failures of RSS components. Comparison of the 17 ½-in. sections of six wells drilled during the Cashima project, where two different bits were used, revealed that there was a total reduction in cost per foot of 25%, and a total comparable savings of approximately 50 hours of non productive time or USD 1.25 million to the operator that could be attributed to the use of the different bits.

This paper will discuss the methodology used to optimize the 17 ½-in. bit for the Cashima offshore field.
Multiphase Simulation of Integrated Hydraulic Fracture/Reservoir Flows Applied to Sierras Blancas Retrograde Condensate
Authors: Fernandez G. , Lolley R. , Quintero A. , Araque-Martinez A. , Kennon S. R.
Published: May 2009

A new method is described that efficiently and robustly simulates multiphase flows in reservoirs with modern complex well completions, such as horizontal wells with transverse hydraulic fractures. These types of completions present a difficult challenge to simulators due to the enormous range of scales in geometry and permeability. For 30+ years, simulators have been restricted to very small ratios of smallest grid block to largest and have been unable to model completions faithfully. Simplified well models with added skin, such as the Peaceman model, have been approximations to real-world completions. The new method, based on a finite element method, manages a prodigious range of scales and correctly implements the physics of multiphase fluid flow.

This paper illustrates the new method in a practical setting: the current exploitation plan of the Sierras Blancas reservoir in Argentina, which requires the solution of reservoir flows coupled to hydraulically fractured vertical and horizontal wells. The models describing hydraulic fractures and reservoir are discretized with a finite element mesh that conforms to both reservoir and fracture geometries and smoothly grades down from reservoir scale to the interior of the hydraulic fracture. Flow inside the fracture is computed along with reservoir flow and is fully coupled.

The Sierras Blancas is a gas reservoir; in the course of exploitation, the hydrocarbon in place behaves as a retrograde condensate. The multiphase aspect of this fluid is modeled with an extended black-oil model wherein the PVT properties of the fluid are derived from lab measurements. As condensate drops out of the gas at the dewpoint, the character of the equations changes from single or two phase (gas, water) to two or three phase, and properties, such as Bg, have slope discontinuities that have historically presented formidable challenges to the numerical modeling of fluid flow. The new method correctly deals with both of these numerical difficulties and the attendant scale challenges.

The behaviour of existing wells in Sierras Blancas, along with hypothetical future, more-complex well designs, is modeled faithfully. Various scenarios are being run with these models being part of a continuous-improvement programme of development of the reservoir to optimize exploitation economics.
A Boundary Element Method Applied to Pressure Transient Analysis of Geometrically Complex Gas Reservoirs
Authors: Wang Haitao , Zhang Liehui
Published: May 2009

Many scholars have used the boundary method to solve pressure transient problems of geometrically complex oil reservoirs. Their research mainly concentrates in oil reservoirs. However, the research on the pressure transient problems of geometrically complex gas reservoirs is very few. The description of pressure transient problems of gas reservoirs is more complex than that of oil reservoirs as the compressibility of gas and the variability of gas viscosity. By deriving rigorously in detail,this paper develops the Laplace space boundary elementary method for solving pressure transient problems in geometrically complex gas reservoirs. The corresponding boundary element models are built and solved. Type curves are computed and drawn. The characteristics of the typical curves are analyzed on the basis of fluid flow mechanism and flow process. The results of this paper not only help us to understand the fluid flow mechanism in this kind of geometrically complex gas reservoir but also can be applied to well testing. The results provide theoretical basis for people to scientifically and economically exploiting reservoirs. Besides, this paper theoretically proves the versatility of BEM in oil reservoir and gas reservoir seepage problems.
First Successful Drilling and Underreaming of Hard, Chert-Rich Formations
Authors: Perez C. , Escareno P. , Arias A. , Castellanos E. , Salazar J. , Urdaneta I.
Published: May 2009

Historically hole-opening and underreaming operations have been restricted to softer formations. This paper describes what is believed to be the first successful drilling and underreaming of a very hard, chert-rich formation.

Many producing wells have been drilled into the deep Cretaceous formations of south Mexico. These consist primarily of hard limestones containing dolomite stringers, large chert nodules, with very erratic hardness and some natural fractures; UCS estimates range from 17,000 to 30,000 psi. On average it takes three TCI bits and two or three PDC bits to drill the Cretaceous interval, which is typically from 4,800 m to 5,400 m TVD.

After several unsuccessful attempts to drill exploratory wells into Jurassic formations below the Cretaceous, the operator redesigned these wells with a contingency casing string. Rig hoisting limitations required each hole interval between conductor and the Jurassic to be underreamed – larger diameter casing strings could not be handled safely. This meant drilling the Cretaceous formation in 8 ½-in. hole and underreaming to 12-in. diameter in order to accommodate the desired 9 5/8-in. casing.

A new eccentric fixed-blade reamer and pilot PDC bit were designed for this application, using latest technology cutters, and profiles, cutter layouts and backrakes, which provided the highest possible durability and thereby gave the best chance of withstanding the high, erratic rock hardness and chert nodules.

The entire Cretaceous interval was successfully drilled and underreamed in a total of five runs. In each case, the assembly was tripped for logging, coring or section TD, with the pilot bit and reamer in good condition. Logging confirmed the desired 12-in. diameter hole. This case history confirms the ability to simultaneously drill and underream hard, chert-rich formations, in this instance greatly reducing the operator's risk of failing to reach their target and giving a wider range of completion options.
Use of Divergent Fluids as an Alternative for Enhanced Recovery in Naturally Fractured Cores
Authors: Lopera Castro S. H. , Restrepo A. , Ocampo A. F.
Published: May 2009

Gas injection is widely used in fields of oil exploration as a method for enhanced recovery. However, this method may be inefficient when producer rock forming favors gas channeling due to heterogeneities. Divergent fluids such as foams have been injected into this type of reservoirs to increase efficiency of scanning, either by reducing gas mobility or by blocking its flow through preferential channels, which can be individual fractures or natural fractures systems.

This study aims to evaluate the efficiency of foams in gas channeling reduction and increase of oil recovery in natural fractured porous medium. A methodology is designed for lab evaluation of foam stability at high temperature, as well as coupling of foam solution and formation fluids, restricting channeling of gas through the fracture(s) and obtaining parameters for optimal performance of tests adjusting to similar reservoir conditions. Using oil recovery as a parameter to measure efficiency of methods, we found that additional recovery is increased an average of 10% once fractures are closed with foam solution, in contrast to fracture closure by increasing of overload pressure. We could verify that foams act as an efficient fluid to block fractures which are common in the rock matrix. Use of divergent fluids allows the increase of crude oil in fractured reservoirs.
A Comparison of Design Placement Methodologies for Horizontal Open Hole Gravel Pack in Multizone Completion Projects
Authors: Loureiro B. V. , de Magalhaes J. V. M. , Martins A. L. , Calderon A.
Published: May 2009

Horizontal Open hole gravel pack is the conventional sand control technique for offshore non consolidated reservoirs in Brazil. Gravel pack placement requirements include the design of pumping pressures inside the operational window formed by the minimum pump rate to avoid premature rat hole screen-out and maximum pump rate to avoid formation fracture. Some special projects require additional equipment to provide selective completion – External casing packers installed at different positions along the production screen aim the isolation of certain reservoir zones. In these cases, gravel pack placement present an additional constraint – operational pump rates should be high enough to avoid alpha wave sedimentation around the packers in order to assure sealing after the packer inflation process. Traditionally, design criteria consider a minimum critical velocity to avoid sand deposition.

The specification of minimum flow for cleaning the ECP, and prevent the deposition of sand in the annular space can be obtained from different criteria. Two methods are proposed to analyze the problem: a constant velocity and a constant shear stress approach. The major contribution includes CFD – computational fluid dynamic simulation of the 3D flow around the packer, using a finite volume method. The methodology based on the estimation of the local shear stresses at the interfaces, suggests less conservative numbers which allows effective gravel pack placement in selective completion projects in narrow operational windows. An illustrative case study with field validation is provided.
Reservoir and Operational Analysis for Steamflooding on Thin Oil Reservoirs
Authors: Gurgel A. R. , Barillas J. L. M. , Rodrigues M. A. F. , da Mata W. , Dutra T. V.
Published: May 2009

This work has the objective of analyzing the influence of some parameters in the continuous steam injection simulation in thin homogeneous reservoirs. Thin reservoirs can be defined as those with thickness between five and fifteen meters. Through sensibility analysis, a study was realized on the influence of operational parameters such as distance between wells and steam rate on cumulative oil production and oil recovery. The study has the purpose of incrementing oil recovery in thin reservoirs similar to those found in Potiguar Basin, Northeast Brazil. The analysis was done using the software STARS- 2007 (Steam Thermal Reservoir Simulation) of group CMG (Computer Modeling Group). Results showed that there is a specific condition of thickness, a steam injection rate and distance between wells that optimizes the oil recovery of the process.
Prediction of Pressure Losses in Drilling Fluid Flows in Circular and Annular Pipes and Accessories
Authors: Scheid C. M. , Calcada L. A. , Rocha D. C. , Aranha P. E. , Aragao A. F. L. , Martins A. Leibsohn
Published: May 2009

This article details an extensive experimental study aiming the evaluation of friction losses resulting from the flow of 4 different drilling fluids in use in deepwater operations through pipe and annular sections, besides accessories such as tool joints, bit jets and stabilizers. After a data analysis process, it was possible to compile a set of equations for prediction of relevant hydraulic calculations, such as: hydraulic diameter for annular flows, friction factors for turbulent pipe and annular flows and discharge coeeficients for accessories.
Energetic Optimization to Heavy Oil Recovery by Electromagnetic Resistive Heating (ERH)
Authors: de Oliveira H. J. M. , Barillas J. L. M. , da Mata W. , Dutra T. V.
Published: May 2009

Electromagnetic resistive heating (ERH) is a thermal stimulation technique in which the electrical current passes through formation increasing the original temperature by Joule effect. Thus, greater is the electrical current intensity, highest reservoir temperatures are reached. This method is much influenced by electrical conductivity of the interested zone mainly due to electrical conductivity of connate water. So, water is directly heated by Joule effect and oil is heated by both conduction and convection heat transfer. In this work, it was studied a combination of time heating without production and heating with concomitant production, which provides a greater economic advantage depending on energy price used and oil price produced, since oil production is increased due to heating provided by ERH.

This method is suitable for use in wide kinds of reservoirs, with different characteristics of reservoir thickness, injectivity, formation permeability, formation porosity, pressure, depth, temperature, oil saturation and oil viscosity. Depending on the energy magnitude delivered to reservoir and formation pressure, this method can be an alternative to in situ steam generation. For offshore productions systems, where the platform surface is limited, the ERH becomes a quite attractive thermal method, been an alternative to steam flooding avoiding heat losses in pipes.

A good strategy for ERH process is, first of all, to choose an electrodes configuration, and after, to control the energy delivered to reservoir, by electrodes voltages, depending of desirable oil rate and temperature obtained in electrodes zones. Electromagnetic resistive heating may produce even better results with water flooding to displace the mobile oil bank after electrical heating, regulating the reservoir pressure and adjusting the electrical conductivity of the system. So, it was possible to optimize the operational parameters to maximize the oil recovery with minimal energy requirement, resulting in an economic advantage.

In this work, it was studied an application of Electromagnetic Resistive Heating in a reservoir with similar characteristics of those found in Brazilian Northeast Basin. The obtained results can be extrapolated to others important applications, for example, offshore heavy oil reservoirs, where, actually, there is no available technology to exploit them.
Influence of Tectonic Stresses in the Permeability of Petroliferous Reservoir in Potiguar Basin, Brazil
Authors: Araújo J. S. , Vieira M. M. , Bezerra F. H. R.
Published: May 2009

Rock permeability is sensitive to the deformation caused by the stresses acting in oil reservoirs. These stresses can be either tectonic, generated mainly by the migration of the lithospheric plates, or lithostatic, caused by the weight of rock layers. Under reservoir conditions, stresses produce anisotropies in the pore spaces. Thus, the recognition of the relation among pore distribution, permeability and stress is important for decisions on planning, development and exploitation of oil reservoirs. The main objective of the present work was to study the relation between tectonic stresses and permoporosity of a reservoir analog in the Açu Formation, Potiguar Basin, Brazil. Oriented plugs were collected, according to the directions of the operating stresses in the basin; these directions were derived from earthquake data (focal mechanism), wells (breakout and anaelastic strain recovery - ASR), fault analysis, joints and dissolution structures, in Quaternary rocks less than 1.0 Myr. From these methods, it was concluded that the preferential direction of the maximum horizontal stress (SHmax) in Potiguar Basin ranges from EW to NW. An outcrop analysis led to the identification of seven lithofacies from which the samples were collected to be used in petrophysical and petrographic characterization. In qualitative terms, it was observed that the porosity found in thin sections is predominantly intergranular, followed by the intragranular (mainly in the interior of the feldspars), inter-crystalline (between the calcite crystals), and oversized types. The petrophysical data indicate that there is no significant difference between porosity and permeability values in both stress directions (SHmax and Shmin). Nevertheless, when porosity values obtained from the description of thin sections are analyzed, it is observed that the highest values are found along the direction of maximum stress. A possible explanation for this discrepancy with petrophysical data is the impossibility of pointcounting, in contrast with the porosimeter, in quantifying microporosity present in diagenetic clays. The foregoing data afford no evidence of the influence of tectonic stress over porosity and permeability in the Açu Formation outcrops. Permoporosityanisotropy, if present, may be caused by other factors such as lithofaciology, that is, sedimentary depositional conditions.
Optimization of Operational Parameters on Steamflooding With Solvent in Heavy Oil Reservoirs
Authors: Galvao E. R. V. P. , Rodrigues M. A. F. , Barillas J. L. M. , Dutra T. V. , da Mata W.
Published: May 2009

The process can be understood as a combination of a thermal method (steam injection) with a miscible method (solvent injection), promoting, thus, reduction of interfacial tensions and oil viscosity. When co-injected with steam, the vaporized solvent condenses in the cooler regions of the reservoir and mixes with oil, creating a zone of low viscosity between steam and heavy oil. Mobility of the displaced fluid is then improved, resulting in an increase of oil recovery and oil rates. To better understand this improved oil recovery method, a numerical study of the process was done contemplating the effects of some operational parameters (distance between wells, steam injection rate, solvent type and injected solvent volume) on cumulative oil produced and oil rates. Simulations were performed in STARS (CMG, 2007.11).

Semi synthetic model was used in this study and some reservoir data were obtained similar to those found in Brazilian Potiguar Basin. The method presented good performance for heavy oil reservoirs with approximately 200 m depth, porosity between 20% and 30%, vertical/horizontal permeabilities ratio of 10% and thickness around 30 m.

It was found that injected solvent volumes increased oil recovery and oil rates. Further, the majority of the injected solvent was produced and can be recycled. For applications of optimized model with oil viscosities of 300 cP, 1000 cP and 3000 cP, the most important oil recovery was obtained for the lightest one (300 cP), while for 1000 cP and 3000 cP, the final recovery was practically the same.

The high initial productions achieved by models that use solvent as an advanced recovery method have normally a significant impact on the operation economics, because early production suggests that fluids injection (steam and solvent) can be interrupted earlier. On environmental point of view, solvent injection can provide a reduction of energy and also a reduction in water consumptions for steam generation, having diminished Green House Gases (GHG) emissions. Also it is important to emphasize that the higher oil rates presented by these models can generate an earlier financial return and, by consequence, a project with a good economical viability.
Water Injection With Fracture Propagation Pressure
Authors: Costa O. J. , Muñoz Mazo E. O. , Schiozer D. J.
Published: May 2009

Water injection is a valuable method for produced water disposal and for reservoir pressure support. A disadvantage of water injection operations is the injectivity loss which can occur due to rock and fluid characteristics, formation damage caused by fines migration and by oil and solid particles present in the water. Optimal injection rates can't be achieved when injectivity loss occur. Nevertheless, the injectivity loss can be mitigated by water injection with fracture propagation pressure (IFPP) which aims to restore injection capacity.

To study this process, a geo-mechanical simulator for fracture modeling combined with a commercial reservoir simulation package is used to model and to optimize the operational conditions of water-injector wells. The fracture is represented by a virtual horizontal well and analytical formulations for hyperbolic decline of permeability represent the effect of formation damage around the injector well.

This paper aims to study some water injection cases to verify in which situations the IFPP use is convenient. The simulation model studied is a synthetic reservoir with a five-spot pattern. Three scenarios are considered with oil type variation (41, 31 and 21 API degrees).

Those scenarios are proposed to reproduce some possible situations that can happen in real field, where formation fracturing pressure can be reached by the effect of the injectivity loss or due to rock and fluid characteristics. The IFPP acting is evaluated using the net present value (NPV) and cumulative oil and water productions.

The results showed that the IFPP study becomes into an optimization problem of injection rate, where the fracture can or cannot occur. It is shown that IFPP, in general, anticipates oil production for cases of intermediate and high oil viscosity, turning a quite advantageous method. Studies in light oil indicate that the technique is only interesting when there is significant injectivity loss, which the IFPP aids in injectivity restoration. It is shown that IFPP can be advantageous, not only in cases where injectivity loss occurs, but also in cases without injectivity loss, in order to anticipate the oil production.
New Approach to Integrate Reservoir and Geological Information in Complex Fluvial-Stratigraphic Environments to Determine Potential Areas for Water Injection Processes
Authors: Sandoval J. R. , Soto C. , Pérez H. , Sandoval J. , Trujillo M. , Castro R. , Gomez V. , Cárdenas F. , Rodriguez E.
Published: May 2009

The geological, economic, and strategic conditions which make the discovery of large petroleum reservoirs a more risky and costly undertaking has resulted in having to consider mature fields and to conclude that the geology and the properties of fluids have an incidence in the final recovery of each reservoir, and that by understanding these factors it is possible to improve the recovery factor. The Lisama Field is located in the basin of the Middle Magdalena Valley, in Colombia, and is operated by ECOPETROL S.A. It is characterized by a complex of fluvial channels with thicknesses of between 10 and 20 ft, a restricted lateral continuity, lateral and vertical changes in the type of rock and depleted producing sands; this resulted in the need for new exploitation strategies which would allow the optimum recovery of the remaining reserves of the field. From a technical screening based on the properties of the rock, fluids, and the reservoir, the review of analogue fields worldwide and the experimental feasibility evaluated in the laboratory, the implementation of a water injection process resulted in a favorable method to be applied to the Lisama Field.

Geological, petrophysical, fluids, and production information was integrated during the identification and selection of areas and stratigraphic intervals with the best characteristics for the implementation of the water injection process. Zone Quality Factor maps, isochors, average thickness and percentage of sand tied to stratigraphic correlations and reservoir rock-type thickness maps were analyzed to obtain the spatial distribution of the more powerful, continuous channels, with more effective pores systems, which, integrated with the production analysis, resulted in the delineation of the areas of interest.

The prediction of the behavior of the water injection and the expected recovery of oil was obtained by means of an analytical and numerical simulation of the injection patterns as established.
An Application of Feed Forward Neural Network as Nonlinear Proxies for Use During the History Matching Phase
Authors: Sampaio T. P. , Ferreira Filho V. J. M. , de Sa Neto A.
Published: May 2009

Reservoir simulation is an important tool used in the industry for reservoir management. While developing a field, a reservoir simulation model is used as a decision tool to select the best development scheme and also to forecast the oil, gas, and water production expected for the field. Uncertainties are much higher at the early phases and, when production data are gathered during the field development phase, most of the time the initial reservoir simulation model needs to be reviewed once the field observed data is not as the same as the predicted by the model. Some of these uncertainties of these input parameters are related to the reservoir rock reservoir heterogeneities.

History matching techniques are used by reservoir engineers to mitigate/minimize the difference between the observed field data and the predicted data and thus assessing the uncertainties. When reservoir models become too big in terms of number of cells and features, the elapsed simulation time increases very much, making the history matching process very cumbersome and, in some cases, very difficult to achieve in an acceptable time. Parallel processing features of some commercial simulators can perform lots of simulation runs at the same time but cannot address and cannot solve the problem in a proper way.

This paper presents an alternative proposition to speed up the history matching process: the application of feed-forward neural networks as nonlinear proxies of reservoir simulation. Neural networks can map the response surface in multidimensional spaces of a reservoir model (i.e. water production, bottom hole pressure etc.) or of an objective function with few number of simulations. The mapped response is then used as a substitute of reservoir simulation runs during the history matching process. The focus of this work is to shown the steps of choosing the best number of hidden layers, the neurons and the training method. An application case is presented using the workflow presented is this work and showing the validity of the proposed methodology for this complex nonlinear problem.
Relative Contribution to Fluid Flow From Natural Fractures in the Cantarell Field, Mexico
Authors: Cruz L. , Sheridan J. , Aguirre E. , Celis E. , García-Hernandez J.
Published: May 2009

In the Cantarell field in Mexico oil is produced primarily from naturally fractured carbonate reservoirs. These types of reservoirs are among the most difficult to develop given the uncertainties associated with detection and characterization, both locally in the well and regionally in the field, of the fracture networks that predominantly control fluid flow. Additional complexities result from difficulties understanding matrix-fracture interactions.

In the last few years, the oil-water contact in the Cantarell field has been advancing, and this has considerably reduced the oil window zone. One likely explanation is that the natural fracture network (which provides most of the permeability in the field) favors production of water and gas over oil. This new challenge has forced Petróleos Mexicanos (PEMEX E&P) to make new efforts to characterize their naturally fractured carbonate reservoirs and improve their reservoir models.

Using the critically-stressed-fault hypothesis, which assumes that the faults and fractures that are hydrologically conductive today are those that are critically stressed (active) in the current stress field, GeoMechanics International (GMI) analyzed image logs of over 20 wells in detail, and constructed a geomechanical model of the Cantarell field, to define the role of the fracture network in fluid flow. In a previous study, GMI used all available data, including seismic data, caliper logs, image logs, electric logs, drilling reports, sedimentological analyses of cores, and regional tectonic studies, to develop a comprehensive geomechanical model of the field. We then used and complement this model in conjunction with all available image logs to predict the orientations of the most and least critically stressed (hence permeable and impermeable) fractures.

The results have been effectively used to improve well trajectories both to minimize costs and to optimize production throughout the life of the reservoir. The results have been particularly useful in horizontal wells, where preventing water production requires avoiding steeply dipping fractures that are critically stressed.
The Use of Well Strengthening for Coping with Losses During Precompletion Operations Prior to Horizontal Open Hole Gravel Pack in Campos Basin Deep Waters
Authors: Pedroso C. A. , Denadai N. J. , Coutinho P. C. , Pinheiro C.
Published: May 2009

The use of the alpha and beta wave technique for a successful Horizontal Open Hole Gravel Pack is based upon a well without, or with minimum, losses. In this case, the gravel particles will be adequately carried to the expected point of deposition. So, in case of any mud losses, both while drilling the reservoir or during pre-completion operations, an efficient loss control method should be used, in order to allow the best packing of the screen with gravel particles.

Besides a brief revision of current techniques, this paper details a well succeeded loss control strengthening operation, when water based drilling fluid was injected during the pre-completion operations of a production well with long horizontal section in Campos Basin.

After the displacement of the water base drilling fluid 9,4 ppg by completion fluid (brine) 9,4 ppg, the well started to lose about 15 bph of fluid. Based upon solid previous experience, an acceptable limit for WBM losses is about 2 bph. The well was reconditioned with WBM, lowering the losses for 5 bph, still too high. So a LCM pill was injected into the formation, above fracture pressure, using the "sealing fracture method". This procedure resulted in a well without any losses, which allowed the displacement by brine, the running of premium screens and complete the pumping of HOHGP without any incidents.
The Use of Saturated Fracturing Fluid to Cope With Hydrate in Gas Wells Located in Ultradeep Waters
Authors: Pedroso C. A. , Denadai N. , Pinheiro C.
Published: May 2009

A potential problem when fracturing gas wells in deepwaters is the risk of hydrate formation during the flow for cleaning the well.

Some alternatives have been used, such as the pumping of alcohol (methanol or ethanol) in the WCT (wet christmas tree) down the chemical lines or the postponement of the cleaning for some months, counting on the gravitational segregation of the fluids in the reservoir. In some cases, these solutions are not enough. In these cases, a possible solution is the combination of a saturated fracturing fluid together with a saturated brine, what reduces the hydrate formation envelope. This solution can be used in conjunction with other providences, such as the use of alcohol or glycol, sub-surface chokes, etc

The present work describes the steps for the development of a fracturing fluid based on saturated brines and the planning, execution and evaluation of fracturing jobs performed in gas wells located in water depths that ranges from 840m to 1950m.
Selection of Infill Drilling Locations Using Customized Type Curves
Authors: Al-Kinani A. , Nunez G. , Stundner M. , Zangl G. , Iskandar O. , Mata T. , Cottone S. , Cavero J.
Published: May 2009

This paper discusses a new workflow to stochastically estimate the performance of infill locations in a mature oil or gas field. Usually performance evaluations for infill wells are conducted using either much generalized statistical methods or numerical simulation. Both approaches have a significant drawback; the prior being quick however very often lacking in accuracy, the latter being very accurate however usually very complex in setup and computation.

The presented workflow is a new approach to infill well performance prediction that combines speed and reasonable accuracy. The workflow generates a set of key performance indicators of existing wells derived from historic dynamic data (fluid production rates, pressures, etc.), static data (reservoir properties, etc.) and predicted data (simplified production forecasts). The wells are then grouped according to the similarity of their KPIs. The production profiles of the wells within the same group are combined to a type curve that is described by the most likely production profile and an associated uncertainty range.

A data-driven expert system is used to identify and capture the correlations of the parameters such as geographic locations, well spacing, reservoir properties and the group membership (equivalent to type curve). This expert system can then be applied to any location in the field in order to determine the most likely group membership of a potential infill well. The classification of an infill well to a group is hereby not necessarily unique; the expert system might classify an infill well into several groups and assign a probability of occurrence for each of the groups. A Monte Carlo routine is then applied to forecast the performance of the infill locations honoring the respective probability of occurrence of each type curve.

The presented approach has been successfully applied for infill well selection in a statistical field development study for YPF in the Argentinean San Jorge Basin.
Noncontinuous Steam Injection Optimization for SAGD Process for Improving Heavy Oil Recovery
Authors: Barillas J. L. M. , Dutra T. V. , da Mata W.
Published: May 2009

Several processes for improved oil recovery are thermal and are based on steam injection. Through these methods is possible to heat the reservoir, reducing oil viscosity and increasing the oil-phase mobility, allowing a better oil displacement in reservoir and increasing swept efficiency. Nowadays, one of the most promising thermal recovery technologies is Steam Assisted Gravity Drainage (SAGD). In this process, two horizontal wells, separated by a vertical distance are placed near formation bottom. Horizontal top well is used for steam injection, which creating a steam chamber which grows upper and to surroundings allow heat transfers between steam and oil by conduction. Bottom well is used for oil production.

SAGD process appears to be technically attractive, due to the high recovery and highs oil rates and oil-steam ratio. This process was applied in country such U.S.A., Canada and Venezuela. In this work, it was idealized a reservoir with some northeast Brazilian characteristics in a homogeneous model. It was done an optimization of steam rate, in a non continuous form, injected steam for several time periods. For the optimization study was also realized a net present value study and it was compare to a process with continuous steam injection. All the cases studied were done using the software STARS from CMG (Computer Modelling Group).

This study showed that, in SAGD process, steam requirement can be reduced by injecting it in a non continuous form, alternating steam injection with stops at several time intervals. It was possible optimized these intervals minimizing heat losses and improving oil recovery. The optimal time interval was found at six months that mean, it can injected steam for six months and then stops the steam injection for next six months. When it was compare to a system with continuous steam injection, was founded that this system had a lower net present value that the system with steam injection with stops. It was founded that was possible to reduce water production, with an improved of oil recovery.

In this work was obtain a way to optimized steam rate, minimizing heat losses and increasing net present value, in reservoirs with some Brazilian Northeast Basin characteristics, and that become important, because it is necessary to improved heavy oil recovery with minimal environments damages, and with lower production cost.