bluuebunny/crossref_metadata_2025 huggingface dataset:
A Unique Workflow for Reserves Evaluation in Lower Vicksburg Sands
Authors: Fan Li , Martin Ronald B. , Sehbi Baljit , Owen Keith W. , Atwood W. K. , Palacio Juan Carlos
Published: December 2007

This paper presents a unique workflow for gas reserves evaluation in fields with commingled production from several low permeability reservoirs. The workflow was originally developed for gas reserves evaluation of the Lower Vicksburg (LV) sands and the paper illustrates the key steps in the methodology. Developing Lower Vicksburg sands has been a great challenge to all operators in the region, not only because of the high drilling and completion cost, but also due to the high risk and uncertainty involved in the process. To make wise investments in such a difficult environment, it is crucial to understand the real value of the remaining reserves.

The outcome of a reserves evaluation depends on the amount and quality of the data, the knowledge and experience of the evaluators, and the methodology and workflow used during the evaluation process. Although we deal with dry gas reservoirs, the challenge lies in the difficulty of solving relatively simple equations that result from a combination of complicated reservoir and production characteristics. As a result, a wide range of answers may be obtained from the same data set and frequent revision of the reserves number becomes unavoidable. However, it has been our experience that the accuracy can be greatly improved through sound engineering practice and workflow. This paper illustrates a robust process to quantify the reserves in the LV reservoirs. This unique workflow includes sound data management and consistent analysis processes that allow for iterations among different methodologies aimed at minimizing the uncertainty and improving accuracy in the results. The paper also highlights some common pitfalls and mistakes normally made today in the reserves evaluation process for low permeability reservoirs, which should prove highly beneficial to the petroleum industry. In fact, the workflow would be useful toward obtaining correct reserves estimations for virtually any low permeability gas field where production from several horizons are commingled without the need of a full field reservoir simulation.

In this paper, we will use a field reserves study as an example to illustrate our unique workflow. The objective was to estimate remaining reserves in the LV reservoirs. The scope of the study includes six Lower Vicksburg sands (namely A sand, B sand, C sand, D sand, E sand, and F sand) found in less than 100 wells. It needs to be pointed out here that any analysis results presented in this paper do not represent the results from the real study. These are strictly for demonstrating the workflow process.
Neural Network and 3D Seismic Techniques Improve the Prediction of Facies Distribution Within a Submarine Channel Complex: Neuquen Basin, Argentina
Authors: Raggio F. , Ortin A. , Martinez C. , Uzzo P.
Published: December 2007

Los Molles Formation in the Neuquén basin (Fig 1), west-central Argentina, contains a series of deep-water submarine channel complexes deposited in an elongate basin, during the Pliensbachian-Toarcian ages. These events developed during the final stages of the rifting phase. In the studied area, these submarine meandering canyons cut the shelf and gentle slope in a SSE-NNW direction, and represent the transfer zone of the system, where erosional features are more frequent and lithological distribution is more complex. The canyons are approximately 3 Km wide and several hundred meters thick and host a number of migrating channel-fill units inside, lying on erosional surfaces that cut into adjacent interchannel facies.

Applying neural network techniques in the three wells that penetrate this deep-marine strata, allowed the identification of five main lithofacies: muddy-matrix conglomerates, sandy-matrix conglomerates, coarse-grained sandstones, fine-grained sandstones and mudstones. Furthermore, the use of 3D seismic attributes was crucial to obtain the distribution of these facies within the canyons. For this purpose, techniques based on neural network and representative supervised "seed points" next to each lithology around the well, were applied.

This work resulted in a seismic volume with the distribution of four seismic facies along the system in a very heterogeneous way. The fine grained facies clearly located in an overbank position; the sandstones and conglomerates show a distribution constrained inside the canyons, and is also easy to see how the net-to-gross relationship increases towards the distal positions of the system.

The techniques applied, greatly improve the success of prediction of potential reservoirs locations.
Well Pressure Behavior for a Vertical Well in a Gas Condensate Naturally-Fractured Reservoir
Authors: Escobar Freddy Humberto , Garcia-Rocha Humberto , Suaza Ivan Mauricio , Cantillo Jose Humberto
Published: December 2007

The complex behavior exhibited by gas condensate reservoirs due to the existence of a two-phase system: reservoir gas and liquid condensate and its implications plus the nature of heterogeneities is the subject of the present article which involves handling of reservoir engineering concepts subject to be interpreted, so that by coupling them with pressure transient analysis using a compositional simulator, we can obtain some patterns which lead to facilitate the understanding of the reservoir's dynamics.

Great volumes of fluids are stored in Naturally Fractured Reservoirs (NFR). Simulation of this type of deposits presents great challenges, from not only the geomechanical point of view but also the thermodynamical modeling of the different phases flowing throughout the fracture system.

In this work, we present an attempt to model a gas condensate formation involving the implications of relative permeabilities to observe their effect on the flow behavior once pressure finally falls below the dewpoint and the effect of the capillary number on the fluid flow phenomena in the near-wellbore region. Interpretation of the pressure test is conducted by the TDS technique.
The Impact of Undersaturation on Coal Gas Economics
Authors: Seidle John P. , O'Connor Leslie S.
Published: December 2007

Many coal deposits throughout the world are undersaturated to some degree. With actual gas contents less than expected from reservoir pressure and the sorption isotherm, these coals require dewatering before gas desorbs. An operator must bear water production and disposal costs, frequently for an extended period of time, prior to realizing any revenue from gas sales. Gas and water profiles for wells completed in Powder River and Greater Green River coals were simulated assuming saturated coals and selected degrees of undersaturation. Base case economics were constructed by combining the simulated gas and water profiles from saturated coals with typical capital costs and well operating expenses for each basin. Gas and water profiles from simulation of ever deeper undersaturation were used to drive additional economic analyses. From this suite of economic analyses, the impact of undersaturation on economic parameters such as net present value, time to payout, and breakeven gas price was assessed.
Improving Reserves and Production Using a CO2 Fluid Model in El Trapial Field, Argentina
Authors: Crotti M. A. , Inlab S. A. , Fernandez Gustavo , Terrado Martin
Published: December 2007

The El Trapial field is a 1.2 B bbl OOIP asset located onshore in Argentina, South America. The field was discovered in 1991. Water injection started in 1993 with current infill drilling and development of some areas still taking place. This field consists of several sandstone reservoirs with average permeability and porosity of 75 mD and 17% respectively. One unique challenge of El Trapial field is that the light oil coexist with gas that contains high CO2 concentrations, greater than 75%. This is observed in both dissolved gas and in gas caps in various blocks of the field. Well documented production data have indicated variations in CO2 concentration in different areas of the field. Conventional fluid modeling could not explain the formation of gas caps at dissimilar structural positions, nor could it explain the existence of oil legs at pressures below the apparent (predicted) bubble point pressure.

A fluid characterization model was performed in the El Trapial field in order to improve the understanding of the PVT behavior at reservoir conditions in the presence of the original high content of CO2. An empirical model was created using the assumption that thermodynamic equilibrium was reached before the time of exploitation. This model shows that the bubble point pressure can increase with depth when light oil coexists with high concentrations of CO2, showing an opposite behavior to what is observed when the gas phase is mostly hydrocarbons. Sensitivity analysis was conducted to identify the key variables that impact this distinctive behavior.

The developed model improved the understanding of the areal and vertical distribution of CO2 in El Trapial. It was used to redesign the development strategy of an area of the field, taking advantage of the oil production at shallow structural depths previously identified as potential free gas zones. Also, the production strategy of the entire field in terms of surface CO2 handling, corrosion prevention and production optimization was revised. This paper illustrates the characterization of this unique behavior, including modeling, application and results.

This proposed model can be applied to other reservoirs where CO2 is present. A methodical approach is presented including laboratory tests, field surveillance and monitoring needs as well as resulting development improvements.
Design and Utilization of Low Solids OBM for Aasgard Reservoir Drilling and Completion
Authors: Fossum P. V. , Van Der Zwaag C. , Taugbøl K. , Mjaaland S. , Sletfjerding E. , Høgstøl H. , Olsen P. A. , Pettersen B.
Published: December 2007

This paper describes the development of a low-solids mineral oil-based fluid and its successful application as a drill-in and completion fluid in a multilateral (MLT) well on Statoil's Aasgard field, off Mid-Norway.

The introduction of highly complex technology, such as multilateral well design with long horizontal reservoir sections, demands a strong focus on the drilling fluid characteristics. Recent field experience showed that conventional oil-based mud (OBM) systems had limitations, when used in a demanding downhole environment influenced by elevated temperatures and ambitious drilling and completion objectives. This resulted in lower than expected drilling efficiency and well productivity. Accordingly, a development program was instituted to qualify a new high-temperature OBM that possessed reduced formation damage potential and superior bridging characteristics while remaining thermally stable.

The candidate fluids investigated were OBM of three different types: 1) standard OBM with a mineral base oil, 2) OBM with a linear paraffinic base oil and 3) a low-solids (LS) OBM. The latter was based on an emulsion with a heavy calcium bromide brine as the internal phase and a mineral base oil as the external phase. Bridging materials and organoclay for viscosity were added as the only solids materials.

The results of the qualification programme showed that the LS OBM exhibited superior sag stability and much higher return permeability values as compared to the two other oil-based alternatives.

The field application of the fluid was very successful. And the Aasgard subsurface team managed to drill and complete a total well path length of about 4900 m. The well was drilled and completed 37 days ahead of plan and produces with a productivity index as expected.
A New Matrix-Acidizing Simulator Based on a Large-Scale Dual-Porosity Approach
Authors: Cohen C. E. , Ding D. , Bazin B. , Quintard M.
Published: December 2007

The principle of a matrix acidizing treatment in carbonated reservoir is to bypass damaged near wellbore zone by creating empty channels called wormholes. The success of the stimulation depends on the ability of an operator to control the unstable process producing those wormholes. Length, size and density of these channels depend on numerous parameters from injection rate to rock properties. Significant efforts have been made in both experimental and numerical studies to optimize stimulation procedures. Today, core-scale numerical models can successfully reproduce the dissolution process, but they are limited in their ability to simulate wormholes at the wellbore scale. Large-scale models are based on semiempirical approaches.

We present in this paper a new simulator for matrix acidizing, built to simulate full acid treatment while considering every mechanism involved in the dissolution process at all physical length scales. It is based on a dual porosity model written at the wellbore scale, and derived from a volume averaging of the Dar?y-scale equations describing acid-rock local equilibrium dissolution. This model can reproduce different types of dissolution patterns, from compact to uniform through dominant wormhole patterns, and it accounts for wellbore-scale heterogeneities. An application of the simulator is presented in this paper. For a given damaged well, we first illustrate the interaction between the wormholing dynamics and the formation heterogeneities. Then we study the optimization of the treatment design, which is function of fluid placement and flow rate. For a set of acidizing parameters, we extract the resulting specific skin factors along the well from simulations. The skin values of each layer are then introduced in a reservoir simulator to calculate the well productivity. An objective function using this productivity change is minimized by an inversion algorithm, to converge toward optimum values of the treatment parameters.
The Centrifuge as a Tool To Determine the Pore-Throat Size Distribution in Plugs
Authors: Martin Carlos A. , Ramia Maximo E. , Barberis Lucas
Published: December 2007

The standard use of the centrifuge is to determine capillary pressure in plugs. What is proposed in this work is to extend its application making it possible to determine the pore-throat size distribution in plugs in addition to the capillary pressure indicated above.

To this end we start with a plug properly cleaned and saturated with the corresponding brine. The plug is then placed in the centrifuge and the collected data consists of the total evacuated brine volume VT(v) as a function of the centrifuge rotation speed v.

A simple model, consisting of capillary tubes running from one end of the plug to the other, is proposed to describe the complex system network of pores and the corresponding interconnecting pore-throats. The corresponding theory, based on treating the capillary pressure as that due to the water-air interphase, is worked out in such a way as to link the capillary size distribution to VT(v) vs. v. The mathematical procedures turn out to be straightforward and the solution is unique. This original analysis of the centrifuge data was successfully applied to a large number of plugs. As an example the corresponding data and analyses are fully given and described. In a companion paper these results are compared with those obtained by MICP (Mercury Injection Core Porosimetry), and the agreement found may be considered as excellent. There is a practical limitation of the method proposed in this work. The capillary pressures that can be reached with the centrifuge are not as high as those that can be reached by MICP. This limitation manifests itself in the fact that pore-throat sizes below 1 μm are poorly detected or not detected at all. However, for pore-throat sizes above that value the agreement is excellent.

The main result obtained in this work is that it is shown that similar information to that produced in a MICP run with two main advantages (1) the centrifuge is a non-destructive experiment, and (2) is a non-contaminating experiment.
Modeling and CT-Scan Study of Foams for Acid Diversion
Authors: Carretero-Carralero M. D. , Farajzadeh R. , Du D. X. , Zitha P. L. J.
Published: December 2007

In this paper we present a 1D and 2D analysis of foam development in porous media based upon a new stochastic bubble population foam model and provide a detailed experimental validation. We present systematic experiments consisting of the co-injection of N2 gas and surfactant solution in homogenous sandstone cores, varying the liquid and gas injection rates. During the experiments X-ray computed tomography (CT) scans were used to map locally the fluid saturations with high spatial and temporal resolution.
Defining and Implementing Functional Requirements of an Intelligent-Well Completion System
Authors: Ajayi Arashi , Konopczynski Michael , Nielsen Victoria Jackson , Giuliani Corrado
Published: December 2007

There are various challenges involved in the design and implementation of an intelligent well system for field development. Different challenges are encountered at different stages of the intelligent well project. In order to arrive at a fit-for-purpose system, each of the challenges will have to be addressed adequately.

These challenges can be categorized under the following: value driver identification, well location, system selection, third party equipment integration, control and monitoring objectives, data management and project management. Addressing these challenges will highlight the relationship between project value drivers, functional well requirements and how these influence the selection of the final intelligent well completion. Provision of feasible solutions to the challenges also requires an integrated approach.

This paper divides the intelligent well completion project into different stages and addresses issues specific to each stage. The authors provide recommendations that increase overall chances of project success and ensure that the promised values of the technology are delivered.
Streamline-Based Integral Modeling for Waterflooding Design Optimization, Surveillance and Monitoring
Authors: Galacho Mirta , Vázquez Pablo , Laiz Gerardo , Krittian Andrés , Gutiérrez Fabián , Pací Victor
Published: December 2007

The Dynamic Numerical Simulation in Flowlines (DNSFL) is an alternative tool adapted to handle Dynamic Models in Fine Scale. This feature has been particularly relevant for studying the current case, a huge multilayered waterflooding process developed in a giant field of great extension reservoirs with considerable facial and stratigraphical variations.

The DNSLF develops these tasks suitably because uncouples reservoir geometry and heterogeneity from transport equations, solving the problems dominated by convective flows in a faster and computationally more efficient way. This allows to build models of greater space discretization and, therefore, to represent better the heterogeneity of the reservoirs.

The analyzed field is constituted by fluvio-lacustrine deposits, nine sand-clay cycles of normal grading (only eight of them were modeled), partially connected reservoirs; with 250 actives wells in commingled production and water injection; and with a long and detailed history of simultaneous primary and secondary events.

In a previous paper (SPE 94815) a Streamline-based Global History Matching of this field was presented. This process enabled to achieve the Geological Modeling Calibration, a clear conceptualization of the current primary and secondary production mechanisms, its productive behavior, and to evaluate the geostatistical and Upscaling procedures to apply for the definition of the Simulation Model.

This paper illustrates how the Integral Model achieved, with a detailed Streamline-based History Matching, is used for Waterflooding Design Optimization, Surveillance and Monitoring, showing that these principles are key factors to understanding reservoir performance and identifying opportunities that will improve the ultimate recovery.

During the detailed History Matching process CPU runtimes around 200 minutes were achieved using a 1225000 grid cells Model, with 190 timesteps, quarterly at the starting, and monthly after, based in a Pentium 4 PC, 3.2GHz CPU and 2GB RAM. It showed that it is possible to work with a big Streamline-based Model in relatively short processing time.
Filtration Effect on Water in Oil Emulsions Stabilization in Slop Crude Treatment
Authors: Ricaurte M. , Perozo H.
Published: December 2007

The emulsion (water, crude and solids) remaining in W/O interface after dehydration (water removal) constitutes Slop crude. Its recovery requires more complex processes than conventional treatment of crude because it has a very stable emulsion and vast amounts of fines. In the oil industry filtration is commonly used to treat crudes with such characteristics.

Shear effect, resulting from filtration of a Slop crude from west Venezuela, on emulsion stability and thereby on its dehydration was studied. Static stability tests, at laboratory scale, were conducted. They were carried out on diluted Slop crude, unfiltered and filtered with different meshes size, at different temperatures, injection of moisturizing and demulsifying products, and settling time.

After treatment, water and sediment content (%W&S) was lower in unfiltered crude than in the filtered one. All unfiltered samples reached commercial specifications (<1 %W&S). The parameter studied to explain how the filtration process affects emulsion stabilization was the determination of droplet size on the Slop crude, before and after filtration.

The microphotographs show that filtered samples have smaller droplet size than the unfiltered ones. Thus, evidencing that shear resulting from pressure drops and partial pluggings of meshes lead to decrease in emulsion droplet size and on increase stabilization. This decrease explains why thermochemical dehydration of unfiltered samples is more effective than that of filtered samples.

Based on these results, it was concluded that solid separation through filtration, prior to thermochemical treatment, is negative to dehydrate the studied Slop crude because a decrease of droplet size on the dispersed phase is produced, there by stabilizing emulsion even more.
Assessment of CO2 Corrosion Damage: Likelihood of Failure in Deviated Wells by Deterministic and Stochastical Modelling
Authors: Case R. , Carpio M.
Published: December 2007

Damage due to CO2 corrosion related processes is a cause of major concern regarding the structural reliability of subsurface installations used in oil and gas production. As to well completions, the effective control of CO2 corrosion includes the complete characterization of the operating environment since corrosion rates and CO2 corrosion morphology are closely related to variables such as the presence of multiphase flow, temperature and produced water composition.

In the present paper an a priori damage assessment methodology is used to analyze casing failures observed in deviated wells with electro submergible pumps (ESP) in the Oritupano oilfield (located in eastern Venezuela). The study analyzes the assessment of CO2 corrosion damage and determines the subsequent probability of failure in relation to the structural reliability of the well. The method proposed is based on the mechanistic CO2 corrosion and multiphase flow modelling in order to deliver a comprehensive quantitative description of the expected corrosion rates within the context of the actual well operating environment and completion design.

The probability of failure is quantified by assessing two independent probability events: damage distribution and the fracture mechanics associated failure probability. The corrosion related damage distribution is calculated by using stochastical simulation of the CO2 corrosion mechanisms, linked to the deterministic corrosion study. The fracture mechanics associated probability is quantified by defining the main operating parameters (such as temperature and bottom hole pressure) as stochastically sensible independent variables within the context of a Level 2 Failure Assessment Diagram (FAD), as defined in API 579.

The results obtained explain the difference observed in the reported work over rates between vertical and deviated wells in the specific oilfield (Oritupano A) using the same extraction methodology. It is also possible to predict consistently the reliability curves obtained from actual field data and discriminate among the possible causes of failure.
Fracture Treatments of Horizontal Wells on Western Siberia Oil Field—Maximizing Long-Term Production
Authors: Baranov Dmitry , Kontarev Roman , Senchenko Dmitry , Faizullin Ildar , Gayfullin Albert , Ivshin Anatoly , Kazykhanova Naylya
Published: December 2007

Recently, several Russian oil-producing companies have started to implement various technologies for stimulation of horizontal wells. Due to significant vertical permeability anisotropy of Western Siberia oil reservoirs, hydraulic fracturing treatments seem to be an effective method of production acceleration and sometimes a method of production enhancement.

In this paper, a comprehensive analysis of horizontal wells fractured from 2005–2006 in the Western Siberia oilfield is presented. This paper will discuss a list of criteria for successful candidate selection, suggest some statistical relationships for post-fracturing production forecasting, and show important factors that affect long-term performance. A new fracture treatment design optimization approach was developed on the basis of the best field practices and results of this investigation.

Simulation studies for testing the obtained results were performed using a multiphase flow reservoir simulator and a pseudo-3D fracture simulator. Three types of studies were investigated: (1) "base" cases representing horizontal well production without fracture treatments, (2) "real" cases, a study of treated well performance, and (3) "ideal" cases, which represented a modeling of horizontal well performance for treated wells on the basis of the developed design optimization approach. The impacts of some important factors—such as reservoir pressure decline in drainage zones on long-term, post-treatment production—were estimated using matched "real case" sector models. Refracture cases were also considered. Comparison of well performance for those cases enabled the estimation of long-term production increases resulting from fracturing treatments and potential incremental production increases expected from implementation of the new design approach for the Western Siberia oil field.

Results from this program resulted in new candidate selection criteria, methods for improving the accuracy of post-treatment production forecasting, and a suggested fracture design optimization approach. These important developments can help maximize long-term performance of the horizontal wells in this Western Siberia oil field and consequently can increase output for the operator from that asset.
Study of Sweep Efficiency of Water Injection under Fracturing-Conditions Process
Authors: Muñoz Mazo Eduin O. , Montoya Moreno Juan M. , Schiozer Denis J.
Published: December 2007

Water injection performance depends on the petrophysical reservoir properties and fluid-flow characteristics. Reservoir simulation models should include rock properties variation and rock-fluid interactions and, when it is necessary, geomechanical phenomena.

When water Injection above Fracture Propagation Pressure (IFPP) is used, its effects over the reservoir model performance, and specially, on waterflooding sweep efficiency, become a critical point to be assessed. Quantification of these effects using parameters such as the Recovery Factor (FR) and Net Present Value (NPV) is important for the water injection project dimensioning and to determine the feasibility and usefulness of the injection process to be implemented.

Water injection under fracturing conditions is an important method to overcome the production decline caused by the injectivity loss in reservoirs with water injection. Also, the modeling of injectivity loss and fracturing processes are subject of several studies, which aim to understand these processes in order to enhance the results to be used for the reservoir development strategy proposal.

The objective of this work is to quantify, using Sweep Efficiency and NPV as study parameters, the effects of anisotropies on the production performance during a waterflooding under fracturing conditions. The methodology proposed considers the simulation of scenarios in which the injectivity loss is represented by an analytical decline model, and the fracture is represented using a virtual horizontal well. This proposal is implemented in order to show the effect of the water injection – injectivity loss – fracturing process on the reservoir behavior. Three different fluid models were used to illustrate their effect in some production parameters and usefulness of fracturing process in several scenarios.

The results show the applicability of water injection under fracturing conditions in different scenarios. In addition, this work shows the importance of the reservoir parameters into the injectivity loss and fracture propagation models, the significance of the FR and NPV in the quantification of these effects. Finally, the relation between the heterogeneity degree and production parameters is presented.
Formation Damage Mechanisms and Their Phenomenological Modeling—An Overview
Authors: Civan Faruk
Published: December 2007

A review and phenomenological modeling of the various processes causing reservoir formation damage are presented. The mechanisms involved in the migration, deposition, and mobilization of the fine particles and inorganic and organic precipitates are described physically and mathematically. The various problems created by fine particles at the pore surface, clogging and dislodgment of the pore throats, aggregation, and interface particle transfer processes in multi-phase fluid systems flowing through porous media are described. The implications of the various mechanical, chemical, and thermal processes on the behavior of the particles are discussed. The various types of shock phenomena and their effects on the particulate processes are explained. The alteration of the pore connectivity, preferential hydraulic paths, permeability and porosity of porous media as a result of the various particulate processes are formulated. The phenomenological modeling of the particulate processes in single- and multiple-porosity reservoir formations is presented. The applications may concern with the damage by particles, injectivity decline in waterflooding wells, formation damage by drilling mud invasion, formation damage in naturally fractured reservoirs, asphaltene deposition, and sand production and gravel pack damage.
Residual-Oil-Induced Injectivity Impairment During PWRI
Authors: Vaz A. S. L. , Bedrikovetsky P. , Furtado C. , de Souza A. L. S.
Published: December 2007

Injection of water with oily particles happens during waterflooding by re-injection of produced water (PWRI). The injected oily particles are captured by porous rock causing decrease of permeability and consequent injectivity decline. Maintenance of the injection rate results in increase of pressure gradient near to well, snap-off the residual oil and additional formation damage due to released drops retention.

We study effects of residual oil mobilization in well vicinity due to pressure gradient increase and, consequently, the increase of capillary number. The mobilized oil ganglia perform snap-off, move together with the injected water; they are captured by rock causing additional formation damage.

The system of governing equations includes mass balances for oil, for particles and equation for desaturation curve. The analytical model derived includes expressions for suspended and deposited particle concentrations, for velocities of concentration fronts and for injectivity decline.

The main result is an additional formation damage induced by residual oil.

Comparison of the injectivity decline models with and without residual oil allows estimate the efficiency of the near-well area treatment by solvent in order to remove residual oil and to reduce injectivity decline.

Another important application of the model is determination of residual oil with PWRI from routine coreflood tests on relative phase permeabilities. If one injects produced water, the formation damage caused by the capture of injected particles and release of excessive residual oil fraction must be taken into account.
A Comprehensive Model for Injectivity Decline Prediction during PWRI
Authors: Paiva R. , Bedrikovetsky P. , Furtado C. , Siqueira A. G. , de Souza A. L. S.
Published: December 2007

Injectivity decline is a chronicle disaster during produced water re-injection (PWRI); the phenomenon has been widely reported in the literature for North Sea, Gulf of Mexico and Campos Basin fields. The damage happens due to solid and liquid particles in the re-injected water. The injectivity decline prediction is important for planning and design of PWRI, of injected water treatment and of well stimulation procedures. The reliable prediction should be based on mathematical modelling using well injectivity index history and laboratory data.

The mathematical models for deep bed filtration of particles and for external filter cake formation have been developed and adjusted to coreflood and well data by numerous authors (Sharma, Khatib, Wennberg et. al.). Here we add modelling of external cake erosion during well closing by the growing cake and filling the well by the erosion particles and develop a comprehensive model.

The comprehensive model predicts very peculiar injectivity index (II) curve: initial II increase due to displacement of oil by less viscous water, slow II decline due to deep bed filtration, fast II decrease during external filter cake formation, II stabilization due to cake erosion during the rat hole filling by the eroded particles and further II decrease during well column filling by erosion products.

The model is implemented in Excel; the software SPIN Simulates and Predicts the INjectivity.

We present in details the history matching for three injectors (field X, Campos Basin, Brazil), showing good agreement between modelling and well data. The obtained values of injectivity damage parameters lay in the same rage intervals as those calculated from laboratory corefloods.
New Method to Squeeze Perforations and Reduce Sand Production
Authors: Ramon F. , Galacho N. , Crotti M. A.
Published: December 2007

This paper describes a new method to squeeze perforations using non toxic chemical products. The product, belonging to the cyanoacrilate family (Ref 1), reacts with connate water dramatically reducing rock permeability in the injected intervals. Some technological solutions using this methodology are discussed. A variation of this methodology can be used to reduce or control sand production in low consolidated sandstones.

At the present time, useless perforations are plugged by squeezing cement into the perforating tunnel. The proposed alternative method is to eliminate fluid conduction through the perforations blocking the permeability in the surrounding formation. To obtain this, non toxic, low cost chemical products are injected to react with connate water, generating a mechanical resistant structure with negligible permeability. A simplified alternative allows for sand control. In this case the proposed methodology the products react partially with connate water, bridging together the sand grains. The chemical product is similar to that used to squeeze the perforating, but at lower concentrations. Several lab tests have been run to check the principles and limits of the chemical products used.

Consequently, it is now available a new system to plug useless perforation by injection of a chemical product, at low cost and operationally safe.

Using this new methodology it is possible to minimize cost and time during workover operation.
Holistic Fracture Diagnostics
Authors: Barree R. D. , Barree V. L. , Craig D. P.
Published: December 2007

Since the introduction of the G-function derivative analysis, pre-frac diagnostic injection tests have become a valuable and commonly used technique. Unfortunately, the technique is frequently misapplied or misinterpreted leading to confusion and misdiagnosis of fracturing parameters. This paper presents a consistent method of analysis of the G-function, its derivatives, and its relationship to other diagnostic techniques including square-root(time) and log(Δpwf)-log(Δt) plots and their appropriate diagnostic derivatives. Actual field test examples are given for the most common diagnostic curve signatures.
Characterization of Sulfate-Scaling Formation Damage from Pressure Measurements
Authors: Bedrikovetsky P. , Marotti M. , Lima Neto I. A. , Carageorgos T.
Published: December 2007

Mixing of sea- and production waters during waterflooding of offshore oil reservoirs results in reaction of barium and sulphate ions causing precipitation of barium sulphate with consequent rock permeability decrease and well productivity decline. The reliable productivity decline prediction is based on mathematical modelling with well-known model coefficients. The sulphate scaling system contains two governing parameters: the kinetics coefficient characterising the velocity of chemical reaction and the formation damage coefficient showing how the permeability decreases due to salt precipitation.

Previous works have derived analytical-model-based method for determination of both coefficients from breakthrough concentration and pressure drop during laboratory coreflood on quasi steady state commingled flow of injected and formation waters. The current study extends the method and derives formulae for calculation of two scale damage coefficients from just pressure drop measurements during two corefloods with two different ratios "formation water: seawater".

Data from series of three corefloods on commingled injection with three different "formation water: seawater" ratios, were treated. Equality of scaling damage parameters as obtained from three different floods in similar artificial cores validates the method proposed.
Attaining Performance, Deliverability and Cost-Effectiveness with Solid Expandable Tubular Systems
Authors: El-Mofty Wael , Rivenbark Mark
Published: December 2007

Successful implementation of solid expandable tubular technology provides a viable example of how reservoir management, petroleum engineering, drilling and technology work in harmony to achieve the ultimate goal—high rate of internal return and expeditious payback. Slimming big-foot wells while minimizing the tapering effect of casing profiles is one of the most cost-effective and technically challenging objectives in modern well designs; this has become safely possible in candidate wells with solid expandable tubular systems.

The technology involves downhole cold-working of steel pipe by expanding the diameter beyond its elastic limits to the permanent plastic deformation region. Studies on hoop-stress resilience during expansion, as well as the mechanical and chemical properties of post expanded pipe promoted the technology for field applications.

The ability to expand casing in situ enables hole size maintenance and conservation of internal casing diameter for increased completion and production efficiency. Smart deployments of solid expandable systems to deliver larger production/injection hole diameters have enabled their use as conduits for surface-controlled selective production/interval isolation devices. This feature has enabled geo-steered laterals to be drilled for extended departures, exposing maximum possible surface area of the reservoir for optimum drainage. Drastic improvements of power water injection placement and reliable zonal isolation as an outcome of smart deployment of this technology have resulted in maximizing efficiency of water-flood and other secondary recovery techniques.

This paper analyzes the value propositions of integrating solid expandable tubular technology in candidate wellbore construction designs. It also addresses the effects of improved reservoir architecture on long-term production profiles and analyzes the positive environmental impact of the technology with parallel focus on techno-economic feasibility and constraints.
Modeling of Facies and Net-to-Gross Ratio Conditioned by Seismic Attribute Maps
Authors: Ferreira Guedes Carlos Conforti , Sarzenski Darci Jose , dos Santos Renato Luiz Almeida , de Almeida Costa Flaviana
Published: December 2007

The facies and net-to-gross ratio (NTG) modeling methodology presented in this paper has been successfully applied on geological characterization of a giant field at Campos Basin, offshore Brazil. Such methodology aimed to preserve the seismic attribute original trend for NTG property in the facies model. In this way, more reliable horizontal parameters could be determined. These are usually hard to obtain, due to the scarceness and huge spacing between wells in an oilfield at its initial development stages.

The technique may be described as follows: Choice of a seismic attribute that shows good correlation with average NTG at wells using programme Log Property Mapping (SIS-Schlumberger Information Solutions). After that one must elaborate a non-reservoir average distribution map (NR=1-NTG map).Generation of reservoir facies proportion maps (three altogether) obtained by facies proportion interpolation at the wells (collocated co-Kriging) using the NTG distribution map as a secondary variable.Determination of horizontal variogram parameters. These are used in the non-reservoir facies simulation (from NTG distribution map) and correlated with vertical variogram range, obtained from well data.Determination of horizontal variogram parameters for each of the three reservoir facies using ratios between horizontal variograms range (two directions) and the vertical ones.Determination of NTG, naming 1 for reservoir facies and 0 for non-reservoir facies.

In the modeling phase, mainly in the upscaling step, a particular interval named inter-stratified has been given special treatment. It shows a NTG value around 50% (against a 85% value for the field as a whole) and has been defined in order to preserve the critical reservoir heterogeneities. Once treated in a different way during the upscaling step, its characteristics can be preserved during the scale transfer, and consequently improving history match.
New Attempt in Improving Sweep Efficiency at the Mature Koluel Kaike and Piedra Clavada Waterflooding Projects of the S. Jorge Basin in Argentina
Authors: Paez Yañez Pablo Adrian , Luis Mustoni Jorge , Relling Maximo F. , Chang Kin-Tai , Hopkinson Paul , Frampton Harry
Published: December 2007

Proposal

Most of the mature waterflood projects at the San Jorge Basin have been affected by two main problems, poor displacement and sweep efficiencies, both have limited the recovery factor achievable.

This paper presents a field trial of a new reactive particulate system in an attempt to improve this volumetric sweep efficiency. This particulate system is being used to treat selected injectors operated by Pan American Energy in the Koluel Kaike and Piedra Clavada fields, located in the southern part of Argentina. The main purpose of this field trial is to demonstrate the ability of the new system to improve oil recovery by diversion of injected water into the poorly swept zones around the thief zone or streaks.

This state-of-the-art technology is able to propagate deep into thief zones and has a novel mechanism of action to overcome the observed limitations in conventional polymer flooding and gel processes. The particles are manufactured having properties which allow it to propagate through porous media with the injection water. Once in the reservoir and under the influence of heat the particle expands to a size that can block pore throats, so water injected after treatment is diverted into less efficiently swept zones.

The paper will describe in detail the mechanism and selection criteria of reservoirs and wells to apply the mentioned IOR technology. Theoretical and practical issues involved at the design of the application, as well as operational and logistics aspects will be also included. Finally, it will include the updated information available from the ongoing pilot tests.
Offshore Exploration in the Golfo San Jorge Basin: A Technological Challenge 100 Years after the Discovery of Oil in Well 2
Authors: Clavijo Ricardo , Effendi Yudistira , Ortin Anna
Published: December 2007

There have been three attempts since the 70s to explore the offshore extension of Golfo San Jorge Basin, a prolific onshore province in Patagonia (Argentina) with more than 100 years of activity. Although some non commercial accumulations were found, none of these attempts was successful to find a discovery with enough oil resources to make an offshore development project viable. In this study we will discuss the reasons for this failure, and the keys for a new attempt in the area.

Besides high crude oil prices have been a triggering factor in this renewed interest, new petroleum system models have allowed the definition of undrilled areas with potential for a feasible offshore development. A number of prospects and leads with moderate geological risk have been defined in these undrilled areas.

The low productivity of Golfo San Jorge reservoirs restricts the possible development options. Chubut Group reservoirs are mainly composed of thin and disconnected fluvial sandstones, with limited petrophysical conditions, leading to multiple independent traps with different reservoir pressures, hydrocarbon types and fluid contacts. Thus, new technologies to be applied in reservoir and production engineering represent a real challenge for the economy of the project.

Different engineering options including new technologies for drilling, testing and production are under study and will be applied to make this new attemp a success. The new reserves consequently incorporated would replace the natural decline of production in the mature onshore areas.
Hydrocarbon Generation, Migration, and Accumulation Related to Igneous Intrusions: An Atypical Petroleum System from the Neuquen Basin of Argentina
Authors: Rodríguez Felipe , Villar Héctor J. , Baudino Roger
Published: December 2007

The stratigraphic record of the Altiplanicie del Payún area, in the Northern Platform of the Neuquén Basin, Argentina, includes Tertiary sills and laccolites that reach thicknesses of up to 600 m. Occurrence of thermally immature oil-prone shales of the Late Jurassic Vaca Muerta and the Hauterivian Agrio Formations is profusely documented in the area. However, when sills have intruded the Vaca Muerta shales, source rock sections become mature, displaying a wide-ranging maturity spectrum spanning thicknesses that exceed 400 m.

Commercial oil accumulations (20-33°API) and oil shows are found along the entire column, both in sandstone/carbonate reservoirs and fractured intrusives reservoirs. Oil-oil and oil-source rock correlations suggest a local generation related to the thermal effect of the intrusive bodies. Concurrently, diamondoid analyses point to mixtures of high-mature (cracked) with low-mature hydrocarbons: oils generated and cracked close to sills are considered to be mixed with oils generated from more distant source rock sections less affected by the thermal effect of the igneous bodies, as they migrate towards the sills and shallower reservoirs.

A 2D model that included the thermal effect of the three main igneous bodies of the area was satisfactory achieved, accounting for thermal maturation, oil and gas generation, migration and accumulation. From the modeling, hydrocarbons migration is favored by elevated generation pressures, source rock fracturing and convective water flows.

The integration of geochemical data and 2D-modeling of petroleum generation and migration related to the thermal effect of the igneous bodies led to the better understanding of this atypical petroleum system.