bluuebunny/crossref_metadata_2025 huggingface dataset:
Driving Completion Technology in Subsea, Multilateral Well with Sand Control and Downhole Flow Control
Authors: Wilson Allan , Allam Robbie , Horne Ken , Ballard Tracey
Published: December 2007

This paper presents a significant case study on the completion of BP's first Subsea, multilateral well incorporating both expandable sand screens and downhole flow-control. Discussed in the paper are the project drivers, completion design philosophy and challenges faced by the multi-disciplinary team throughout the planning and execution of this highly complex well. The paper will also present the operational issues and improvement opportunities identified and finally discuss the potential future applications for these technologies in this and other BP fields.

The Schiehallion field is situated on the Atlantic margin of the United Kingdom Continental Shelf (UKCS) some 175 km west of the Shetland islands in water depths of between 350 and 450 m. Schiehallion FP02 was planned as a multilateral well in order to maximize the reserves delivery from the North West Area Development of the field and also provide significant cost savings over the alternative two well options. In order to fully realize the benefit of the multilateral well option, down-hole flow-control (DHFC) was also required to optimize reservoir management and reserves recovery by independent control of the two individual well-bores. Sand control was provided by expandable screens.

Schiehallion well FP02 was successfully completed in July 2006. All of the main objectives were achieved and the well delivered both ahead of schedule and under budget. Incorporating DHFC in conjunction with open-hole sand-control introduced a number of industry and BP technology "firsts" throughout the well construction process. The successful introduction of these various technologies is attributed to rigorous planning and meticulous attention to detail.

The success of FP02 has been a major milestone in the business unit technology plan, demonstrating that combining these technologies is a viable option in this environment. As infill drilling targets become smaller, this technology has the potential to reduce development costs and therefore extend field life.
Study of Skin Damage in Unconsolidated Sandstone by Computed Tomography
Authors: Sales E. S. , Bianco L. C. B. , Queiroz Neto J. C. , Campos E. F. , Lopes R. T.
Published: December 2007

It is well known that the porous media invasion by components of drilling fluids decreases near wellbore permeability and it is one of the factors that generate poor well productivity or injectivity. Permanent changes on the original permeability decrease well flow capacity and only can be evaluated after a well production test. The quantification of the difference, the damage, is defined as the mechanical skin. Among others, two particular factors contribute for mechanical skin during the drilling process: reduction on the oil or gas saturation by the drilling fluid filtrate and reduction on the effective porous throat size by bridging or aggregation of solids and other components.

The measure of the damage, its extent and remedial treatments has been studied since a long time using the API linear flow cell and filtration tests. However, the results obtained with this equipment do not allow an effective quantification that could be applied directly to the field mainly because of the test geometry.

In this study, a technique to quantify physically the damage has being evaluated, using a physical simulator composed by a X-ray transparent radial flow cell, hollow cylinder synthetic sand core sample saturated with mineral oil after full water saturation, the X-ray Computerized Tomography (CT) and a procedure to evaluate the permeability return. The invasion profile for water-base drilling fluid components were mapped after drilling simulation and the residual damage was quantified after an oil production period.

The results of this study showed that: permanent changes occurred on the porous media structure, which incorporated drilling fluids components at the grain and oil saturation was dramatically reduced. Both damages were not removed with the reverse flow of oil, generating a relative oil permeability reduction that was calculated in terms of mechanical skin associated.
Optimization of Stimulation Treatments in the Wamsutter (Almond) Formation by Means of Prefracture Impulse Diagnostic Tests
Authors: Rajappa Bharath , Maudgalya Saikrishna , Sullivan Richard B.
Published: December 2007

The Wamsutter (Almond) formation in southwest Wyoming is a tight gas reservoir in the eastern part of the Greater Green River Basin (GGRB). The Almond formation is generally encountered between depths of 8,500 and 10,500 feet with reservoir pressures varying from initial conditions (0.54-0.58 psi/ft) in the Lower Almond to varying stages of pressure depletion in the Upper Almond. The Almond interval is generally completed via massive hydraulic fracture stimulation down casing with a series of treatments targeting the Lower, Main and Upper Almond intervals. These zones are subsequently commingled for production.

In the absence of reservoir properties such as in-situ reservoir permeability, reservoir pressure, and closure stress, it has been difficult to optimize the stimulation treatments on a zonal basis. To identify these reservoir characteristics, pre-fracture impulse injection testing has been performed in each interval. These simple, easy to perform transient tests have aided in the interpretation of the key reservoir parameters.

This work presents data from eleven wells in the Wamsutter field and describes the methodology used to optimize the stimulation treatments. Reservoir properties obtained from the impulse tests helped eliminate the addition of nitrogen to the fracturing fluid, which had been routinely included to aid fracture clean-up after fracture stimulation. This design change has led to more effective fracture stimulation treatments yielding higher gas production rates while significantly reducing completion costs.

Production from wells stimulated with the modified design is compared to production from wells that were stimulated without the benefit of reservoir properties obtained from the pre-fracture impulse tests.
Field Studies of Drilling and Completion Fluids to Minimize Damage and Enhance Gas Production in Unconventional Reservoirs
Authors: Penny Glenn , Pursley John T.
Published: December 2007

Field data and lab data are presented for various fluids pumped in low perm shales, coalbed methane and tight sandstone reservoirs. Commonly used surfactants, alcohols as well as a microemulsion system (ME) are evaluated. Lab data is presented that illustrates the cleanup of injected fluids in tight gas cores. Damage mechanisms are shown to be phase trapping and high capillary pressures. The microemulsion additive results in lower pressures to displace injected fluids from low permeability core samples over conventional surfactant and methanol treatments. The observed enhanced relative permeability mechanism is the alteration of the rock-fluid interfacial tension or contact angle. It is demonstrated that this alteration effectively lowers the capillary pressure and capillary end effect associated with wellbores and fractures in low perm reservoirs by as much as 50%, thus mitigating phase trapping and therefore permitting an increased flow area to the wellbore following drilling and hydraulic fracturing.

Over 300 wells were evaluated that were drilled and/or fracture treated with various fluid combinations in the Barnett, Fayetteville and Appalachian basin shales. Some 200 wells are examined in the San Juan Basin and other low perm areas such as the Pieance Basin, Uinta, Vicksburg and Cotton Valley. Drilling examples are shown for several horizontal wells. The addition of the microemulsion to fracturing treatments has resulted in more than 50 to 100% increases in load recoveries and gas production. Production analysis of horizontal wells drilled and cleaned up with the microemulsion shows a doubling of production over offsets. Pressure analysis of fractured wells shows that the damage factor is reduced by a factor of 2 with the inclusion of ME.

This is a result of a combination of reduced depth of invasion, a higher relative perm in the invaded zone and/or longer effective frac lengths.
Modeling Non-Darcy Flow and Perforation Convergence for Vertically Fractured Wells
Authors: Huang H. , Ayoub J. A.
Published: December 2007

Non-Darcy flow reduces the productivity of fractured and frac and pack wells and causes erroneous results if ignored when analyzing well test data.1 Current practices to quantify the non-Darcy flow effect in a vertically fractured well are mostly based on the work of Guppy et al.,2-6 where simple empirical correlations were developed in the form of apparent dimensionless fracture conductivity as a function of the true dimensionless conductivity and the inertia resistance factor. However, based on the parameter matrices of their numerical analysis, restrictions were also imposed on the variables for the correlations to be valid. In this paper, the same problem of non-Darcy flow in a vertically fractured well is revisited for the cases of rate-controlled drawdown tests. We argue that the relationships between the apparent fracture conductivity and the true conductivity is a function of time and that the restrictions on variables can be relaxed. In addition, the issue of flow convergence near the perforation tunnels is also discussed. A comparative study of the relative effect of flow convergence vs. flow in the perforation tunnels is also presented to allow a quick assessment of the most dominant factor.
Optimal Scheduling of Well Treatment in Commingled Formations Undergoing Near-Wellbore Damage
Authors: Civan Faruk
Published: December 2007

Methodology and theoretical considerations are presented for scientifically guided optimal scheduling of well treatment in reservoir formations involving commingled pay zones of different properties.
In-Situ Erosion of Damaged Formation During Injectivity Decline (PWRI and Seawater Flood)
Authors: Bedrikovetsky P. , Furtado C. A. , de Souza A. L. A. , Siqueira F. D.
Published: December 2007

Injectivity decline with further stabilisation was widely observed and reported in the literature. It can be explained by different physical mechanisms. The correct diagnosis of formation damage mechanism allows choosing the right damage removal technology during seawater injection and Produced Water Re-Injection (PWRI). Reliable prediction of injectivity decline is essential for planning of well stimulation, fracturing, etc.

Usually the stabilisation of well injectivity index after decline is explained by erosion of external filter cake, or by warm holes or even by fracture opening. Nevertheless, the stabilisation is observed in corefloods too, which evidences internal erosion. So, particle deposit erosion must be considered to interpret the injectivity stabilisation.

In the current paper, the particle erosion was described by introduction of a new particle storage capacity function which equals to maximum retained concentration versus dimensionless flow velocity. After the maximum is reached by the retained concentration, particle capture does not happen any more. The particle storage capacity function is a reological characteristic that closes system of governing equations.

The coreflood by suspension with permeability stabilisation was performed with a constant injection rate. The pressure drop on the core and the rate have been measured during the flooding. The analytical model developed allows to perfectly match the experimental impedance curve and calculate from it three injectivity damage parameters – filtration and formation damage coefficients, and also the maximum retention concentration. The obtained values of filtration and formation damage coefficients are in the usual variation range for these coefficients.

Introduction of just one new parameter – maximum retained concentration – into a classical suspension filtration model allows for significant enrichment of the physics schema for suspension transport and retention. An analytical model of suspension coreflood with piecewise constant rate shows that after changing the flow velocity from some value and coming back to the same value, the impedance returns to the initial constant velocity curve. It takes some time after an abrupt flux decrease to stabilise the resistance growth rate, while the resistance growth rate stabilises immediately after abrupt flux increase. If flow regime changes from low velocity to high velocity, there appears a short particle pulse at the outlet; it does not happen when velocity changes from high value to low value.
Applications of Organic Geochemistry in Rayoso Formation Characterization: Chihuido De La Sierra Negra, Lomita Field, Neuquina Basin, Argentina
Authors: Lovrincevich E. , Fasola M. , Labayen I.
Published: December 2007

Organic geochemistry has been widely used in oil exploration industry. However, only in the last decades, innovative applications of its methods have become known in field development activities and reservoir characterization. One powerful application is the lateral and vertical fluids continuity in reservoirs.

This study was made in Chihuido de la Sierra Negra-Lomita field, Neuquina Basin, which produces from three main reservoirs: Low Troncoso Formation, Avilé Formation and Rayoso Formation.

In the mature stage of field development, RepsolYpf developed an analytical technique based in organic geochemistry to discriminate the production from each reservoir in commingle produced oil samples.

The goal of the present paper is the integration of the geochemistry results and the geological model of the Rayoso Formation in order to establish the lateral and vertical continuity of the reservoir fluids, seal rock quality variations and support the field developments activities.

According to the obtained results, the following conclusions were reached: a) Rayoso Formation produces oils with different geochemistry characteristics and b) The geochemical characterizations of the oils produced in Rayoso Formation is going to be used as a powerful supporting technique for field development.
Analysis of Condensate Buildup and Flow Impairment of Retrograde Gases in Fissured Reservoirs
Authors: Ayala H. , Luis F. , Radespiel Eduardo , Turgay Ertekin
Published: December 2007

Reaching dew-point conditions upon depletion in a near-critical gas reservoir results in the precipitation of a liquid hydrocarbon phase or condensate dropout. Condensate dropout is usually immobile and impairs the flow of the other phases, adversely affecting reservoir productivity and ultimate recovery in this type of gas reservoirs. In the case of fissured reservoirs, the high-conductivity channels supplied by the fracture network will be prone to faster depletion upon fluid withdrawal. Condensate dropout would then occur in the fracture network first and then in the external edges of the matrix blocks. Even though condensate dropout in the fracture may have considerable mobility, this is not the case for the liquid formed at the external portions of the matrix. In this scenario, liquid buildup will hinder the flow of hydrocarbons from the inner portions of the matrix blocks and severely obstruct their recovery. This study aims at the numerical tracking of the liquid barrier, which requires a fine discretization of the inner portions of the matrix blocks, and the analysis of the interplay between the condensate barrier and hydrocarbon flow within the surrounding matrix/fracture system. While traditional wisdom dictates that reservoir condensate dropout is undesirable because this valuable condensate may be completely lost to the formation, this study analyzes if the situation is even worse for the case of fissured systems. In addition to low surface condensate recoveries, condensate appearance in fissured systems may also indicate that the inner-block gas stored in the matrices—where the bulk of the reservoir storage resides—might be also unrecoverable. In this study, guidelines for the development of this class of reservoirs are presented by identifying the controlling parameters of system behavior and ultimate recovery and analyzing the depletion characteristics of near critical fluids in fissured systems.
Pressure and PVT Uncertainty in Material Balance Calculations
Authors: Garcia Carlos A. , Villa Jose R.
Published: December 2007

Original Oil In Place (OOIP) calculations based on material balance methods are strongly influenced by data uncertainty. Although some research is available in literature, usually the effects of data uncertainty on material balance calculations are rarely considered and quantified in most studies. This work presents an approach to properly quantify and account for the impact of reservoir pressure and PVT data uncertainty on material balance calculations under different drive mechanisms and using different material balance methods. This study allows reservoir engineers properly select the most suitable material balance method when uncertainty on reservoir pressure and PVT data is significant.

In this work, two different methodologies are proposed. First, a sensitivity analysis was conducted using generated realizations of reservoir pressure and PVT data to evaluate their effect on material balance calculations. Second, a more robust approach was proposed using experimental design and analysis of variance to systematically evaluate the influence of reservoir pressure and PVT data on material balance calculations in an optimal and integrated fashion. In both methodologies, different material balance methods were used and computed OOIP were compared to reference values from a conceptual reservoir model with known PVT data and simulated reservoir pressure. A MATLAB-based program, with graphical user interface, was coded for this purpose1.

Application of the proposed methodologies allowed to determine and quantify the most significant parameters that influence material balance calculations. Interestingly, the most important parameter was the selected material balance method used to compute the OOIP. More accurate results were obtained using the traditional graphical method (F -We vs. Et) for volumetric oil reservoirs with minimal pressure and PVT data uncertainty. In those cases with moderate to significant water influx and gas cap, and some uncertainty on pressure and PVT data, less accurate original oil in place was obtained when graphical methods were used. Reservoir pressure uncertainty was the most significant parameter on the material balance calculations. Gas-oil ratio uncertainty was also significant. Oil and gas gravity, and reservoir temperature were less significant.
Estimation of Permeability from Porosity, Specific Surface Area, and Irreducible Water Saturation Using an Artificial Neural Network
Authors: Basbug B. , Karpyn Z.
Published: December 2007

An Artificial Neural Network (ANN) was designed and tested in the present study to examine the correlation between permeability estimations and porous medium properties, such as porosity, specific surface area, and irreducible water saturation. The network developed in this work is a predictive tool that uses soft computing techniques to estimate absolute permeability of carbonate reservoirs. The Artificial Neural Network toolbox of MATLAB® R2006b and the Feed Forward Error Back Propagation methodology were used in the construction of the network. Carbonate reservoir field data presented in the literature were utilized in the training, testing, and validation of the proposed model. The present study indicates that ANN generated permeability values are consistent with those obtained from core analysis. Results from this study confirm the complex relationship among permeability, porosity, specific surface area and irreducible water saturation of carbonate reservoirs, and suggest that variations in specific surface area affect the magnitude of irreducible water saturations, thus creating an apparent dependence of permeability on irreducible water saturation. Additional observations support a direct relationship between porosity and permeability, and an inverse relationship between specific surface area and permeability.
Using Seismic Attributes in Petrophysical Resevoir Characterization
Authors: Costa Flaviana , Rodriguez Carlos , Sarzenski Darci , Guedes Carlos
Published: December 2007

The use of seismic attributes has increased, especially when extracted from interpreted horizons. The various available attributes are not independent from each other but represent, in fact, different ways of presenting and studying fundamental information from seismic data (time, amplitude, frequency and attenuation). However, statistical analysis using attributes must be based on geological knowledge and not only on mathematical correlation. Petrophysical studies and seismic modeling are sources of understanding. Such knowledge is necessary to improve confidence in observed correlations with reservoir parameters and must be part of all attribute analysis.

However, the use of seismic attributes leads to several questions, for example, what do they all mean? When to use one or another? How to use them on geologic modeling? How reliable those data are? The answers to these questions are not easy, but considering about petrophysical modeling (Porosity, NTG and permeability) what is the best approach: to consider only well data, that are punctual and need to be interpolated, or try to find correlation with physical measurements (seismic data)? Not to consider seismic attributes makes one feel coming back in time, when this important tool was not available.

On a giant oilfield offshore Brazil seismic attributes (‘conventional’, complex trace, polynomial decomposition, geometric and coherence) have been used to create geological models and to reduce uncertainties. The attribute choice must be performed by the geophysicist and the geologist working together, in order to check geological meaning of attribute maps, possible physical meaning of the attribute, etc. Plots of the highest correlation values should be visually inspected in order to choose the attribute with best correlation to the desired parameters.

The results show attributes have been favourable to porosity and NTG prediction, but regular (at maximum) to permeability. For permeability even if the results are not so good, the correlation are improving for the latest models (as long as new wells are used). Polynomial decomposion and complex trace attributes have shown better results.
Identifying Reservoir Potential in Shale-Dominated Thinly Bedded Clastic Reservoirs With a Near-Well-Bore Modeling Approach
Authors: Phillips Peter , Liwanag Janice
Published: December 2007

Declining output from conventional reservoirs has led to an increased interest in unconventional reservoirs, some of which are characterized by low permeability, shale-dominated, thinly bedded clastics. Historically, these reservoirs have not attracted attention as hydrocarbon exploration targets because of their inherent low deliverability and because it has been difficult to recognize net pay with conventional technology.

This paper presents a geological modeling and upscaling method that can help to identify net reservoir below the level of conventional petrophysical log resolution by modeling small-scale sedimentary details that can impact reservoir performance. The approach combines deterministic and stochastic modeling methods to generate 3-D near-well-bore models that capture laminar-scale, bedding-scale, and lithofacies-scale sedimentary structures. Using these geologically realistic models as a basis, we generate petrophysical models that honor input data derived from core plugs, core observations, and well log data. We then apply flow-simulation-based upscaling methods to derive effective properties for input to full-field reservoir simulations. The output includes pseudo-log curves of net-to-gross, porosity, directional permeability (kx, ky, kz), and the ratio of vertical to horizontal permeability (kv/kh) for a modeled well interval.

The modeling and upscaling approach was applied to a thin-bedded reservoir study to produce net-to-gross reservoir curves based on a geologically realistic distribution of sand and shale. The study identified a well interval where model-derived permeabilities were substantially higher than permeability estimates derived with the conventional phi-k transform. These results were consistent with core observations and core plug measurements, and accounted for original discrepancies between the static and dynamic reservoir model. The geomodel-based upscaling method provided more accurate permeability results and, hence, more appropriate cut-offs for estimating net-to-gross sand.
Geometric Models of Porosity Reduction Mechanisms in Tight Gas Sands
Authors: Mousavi Maryam A. , Bryant Steven L.
Published: December 2007

Pore volume reduction of sediments by plastic deformation during compaction and by cementation of grains has been evaluated for different proportions of ductile and hard grains. We attempted to produce the compaction behavior of grains with a purely geometric model, which uses the cooperative rearrangement algorithm to produce dense, random packings. To account for deformation of lithic grains, we used the soft-shell model, in which grains can interpenetrate until their inner rigid cores come into contact. We varied the fraction of grains assumed to be ductile and the radius of the rigid core of the ductile grains. By changing these two variables, we can have very small values of porosity after compaction of our packing, which is the character of tight sands. The predicted relation between the fraction of ductile grains in the sediment and the porosity after compaction agrees well with experimental data from Pittman and Larese (1991)1. The radius of the rigid core of the ductile grains proves to be a good proxy for different kinds of ductile material, ranging from brittle to extremely ductile. We simulated diagenesis in our compacted rock by considering quartz precipitation. The overgrowth or rim cement was modeled by uniformly increasing the radius of all the grains, while holding their centers fixed. These simulations yield detailed descriptions of pore scale geometry resulting from processes common in forming tight gas sandstones. Such models in turn can provide insight into two-phase flow properties of these reservoirs, particularly the sensitivity of gas permeability to water saturation2.
Application of the ß-Integral Derivative Function to Production Analysis
Authors: Ilk D. , Hosseinpour-Zonoozi N. , Amini S. , Blasingame T. A.
Published: December 2007

In this work we present the application of the β-integral derivative function for the interpretation and analysis of production data. The β-derivative function was recently proposed for the analysis and interpretation of pressure transient data [Hosseinpour-Zonoozi, et al (2006)], and we demonstrate that the β-integral derivative and its auxiliary functions can be used to provide the characteristic signatures for unfractured and fractured wells.

The purpose of this paper is to demonstrate the application of the "production data" formulation of the β-derivative function (i.e., the β-integral derivative) for the purpose of estimating reservoir properties, contacted in-place fluid, and reserves. Our main objective is to introduce a new practical tool for the analysis/interpretation of the production data using a new diagnostic rate and pressure drop diagnostic function.

This paper provides the following contributions for the analysis and interpretation of gas production data using the β-integral derivative function: Schematic diagrams of various production data functions using the β-integral derivative formulation (type curves).Analysis/interpretation of production data using the β- integral derivative formulation.
Effects of High-Pressure-Dependent Leakoff and High-Process-Zone Stress in Coal Stimulation Treatments
Authors: Ramurthy Muthukumarappan , Lyons Bill , Hendrickson Randall B. , Barree Robert D. , Magill Douglas P.
Published: December 2007

Hydraulic fracturing in coals have been studied extensively over the last two decades. However, there are factors that were often ignored or diagnosed incorrectly resulting in screenouts. Assuming that a majority of the perforations are open and there are no problems with the stimulation fluids, screenouts during coal hydraulic fracture treatments can be attributed to either high pressure dependent leakoff (PDL), high process zone stress (PZS) or in some cases both. The objective of this work is to discuss, help identify and present solutions to address these reservoir related issues such that screenouts can be avoided in optimized re-fracture treatments and new well stimulations.

The tools for identifying these reservoir related parameters include Diagnostic Fracture Injection Test (DFIT) and a grid-oriented fully functional 3-D fracture simulator with shear decoupling. An example for each respective case is presented in this paper. In the first example, where high PZS was considered to be the dominant reason for screenout or pressure-out, the well was re-stimulated successfully by implementing the solutions presented in this paper. In the second example, where high PDL was considered to be the main reason for screenout, there were several wells in the same project area that exhibited the same behaviour resulting in screenouts. After implementing the solutions presented in this paper to address high PDL all new wells were stimulated successfully without any issues.
Field Case Studies of Completion FluidsTto Enhance Oil and Gas Production in Depleted Unconventional Reservoir
Authors: Pursley John T. , Penny Glenn , Benton John , Nordlander Gary , McDougall Mike , Greene David , Crafton James W.
Published: December 2007

A study of completion techniques in depleted/low pressure tight permeability gas/oil reservoirs shows great promise through the use of a microemulsion (ME) additive in energized fracture stimulation treatment of new infill wells. This paper presents a comparison of four (4) wells completed according to historical stimulation practices and two (2) wells completed with microemulsion additive. See Table 1 for baseline data.

The damage mechanisms from past practices were exacerbated by depleted/ low bottom-hole pressures, high water saturations, and low bubble point crude. The use of the microemulsion additive reduced the liquid load and promoted liquid recovery, enabling the base fluid gases to establish gas saturated pathways and promote the production of the natural solution gas that is the field's primary economic resource. CO2 is thought to enhance this process by promoting the reduction of the near fracture face oil saturation. The microemulsion potentially enhances this action by reducing the mobility contrast between introduced fluids and reservoir oil, water, and gas phases.

Analysis of the production histories shows that the microemulsion additive significantly enhanced the reservoir conductivity and effective fracture length when compared to the historical completions when in sustained production. The two wells treated with microemulsion additive also experienced less damage as a consequence of the long shut-ins prior to sustained production, than did those with historical completions, which had much shorter shut-ins.
Internal Formation Damage Properties and Oil-Deposition Profile within Reservoirs During PWRI Operations
Authors: Ochi Jalel , Rivet Pascal , Benquet Jean-Claude , Détienne Jean-Louis
Published: December 2007

To predict correctly injectivity for Produced Water Re-Injection (PWRI), a good description of the formation damage by oil and solid particles have to be introduced in simulators for both fractured and non fractured flows. It is well known that the complex mechanisms of the formation of an external filter cake and of a deep internal damage should be better understood. In a previous published work1 we attempted to quantify the petro-physical external filter cake properties. In this paper, results from core flood experiments (CFE) aimed to quantify the internal damage are presented. In recent published works, CFE were performed to examine, along rock samples, the deposition profile of only solid particles. The present work focuses on the oil droplets deposition profile. The mechanisms and laws governing the internal damage with oil are different from those concerning solid particles. Like solid particles, oil tends to deposit preferentially at the core entrance but quickly a moving front of oil droplet is generated. According to our experimental results a simple method for modeling the evolution of the internal damaged permeability is presented and finally an attempt is made to extrapolate these results to the well scale for both matrix and fractured flows.
The Dendritic Well: A Simple Process Creates an Ideal Reservoir Drainage System
Authors: Rae Phil , Di Lullo Gino , Moss Paul , Portman Lance
Published: December 2007

Oil and gas wells are constructed with the intention of accessing and recovering hydrocarbons from permeable rock formations. Ideally, we would like to do that as quickly and as efficiently as possible. Unfortunately, we generally try to accomplish this goal by drilling only a few wells and depending on the native rock permeability, or the presence of natural fractures, to convey hydrocarbons to these few wells. This process is inefficient and, ultimately, leaves significant reserves unrecovered.

Natural processes often offer valuable insight into the most effective ways to exploit, or distribute, resources. If reservoir engineers could drill wells, they would surely not drill a single, small diameter hole, with the walls of that hole damaged to the point they are initially impermeable. They would more likely construct a network of branches, mimicking the root structure of plants, evolved to efficiently drain nutrients from a soil reservoir. This type of network, for the collection or distribution of materials, is a frequently repeated feature in natural systems and clearly represents a highly efficient method to access resources, of one kind or another. Such a network could maximise the contact between reservoir and wellbore and distribute inflow across an enormous surface area. This is the "Dendritic Well" – until now, an impractical concept but one that may have some future with further refinement of the technique reported here.

This paper describes several wells where multiple, relatively short-length laterals were constructed by pumping hydrochloric acid though a specially designed jetting assembly, attached to the bottom of a 1/" coiled tubing unit. This revolutionary method creates a "reservoir engineer's" hole, using simple equipment at low-cost. A highly stimulated lateral tunnel, branching from the original well with a fractal of smaller branches (wormholes) born out of the lateral hole, mimicking a plant root, is the end product.
Structural Styles and Tectonic Framework of the Fold and Thrust Belt in Tierra del Fuego and Offshore Austral-Malvinas Basins, Argentina
Authors: Martínez Pedro Bonillo , Figueroa D. , Ghiglione M. C.
Published: December 2007

Description

The Andes Patagónicos bend to the east at the latitude of Tierra del Fuego island, were they constitutes the Cordillera Fueguina. This cordillera plunges eastward into the offshore and represents the southern border of Austral and Malvinas basins.

The studied area includes the outer foothills of the fold and thrust belt located in Austral and Malvinas basins and their associated tertiary foreland deposits.

The regional tectonic framework is mainly a resultant of the interaction between South America, Pacific, Antarctica and Scotia plates during Late Cretaceous and Tertiary times.

The fold and thrust belt of Malvinas basin is a frontier area where no hydrocarbon exploratory wells have been drilled so far. Most of the data available are 2D regional seismic lines. Repsol YPF, as the operator of a consortium, recently acquired a 2500 km2 3D survey on this fold and thrust belt.

Five restored cross sections in the area are shown and its timing reconstructed. Once the cross sections timing is established, it's associated and related to the tectonic evolution of the area.

Application

Once the traps formation timing is defined, a reliable basin modelling can be performed to reduce the uncertainty associated to the trap charge and type of hydrocarbons.

Result, Observations and conclusions

The structural style is quite variable along the outer foothills region. It changes eastward from a thin skin deformation style in Tierra del Fuego (Argentina) to a thin skin combined with basement inverted faults in Malvinas basin. The main decollements are Lower Cretaceous and Paleogene shales.

The evolution of the fold thrust belt has been mainly controlled by the Scotia Plate activity, resulting in an intercalation of compressional/transpressional periods with others of extensional/transtensional character.

It is postulated that the structures studied in the outer foothills were developed during Oligocene and Lower Miocene times. These ages correlate quite well with a period of high oceanic crust generation at Scotia Plate.

Significance of subject matter

In a fault thrust belt, different compressive pulses configure the traps final geometry. The timing of these different pulses is critical for a correct basin modelling and a prospects risk evaluation.
Use of Discrete Fracture Network "DFN" to Characterize and Model a Naturally Fractured Sandstone Reservoir: A Case Study of Orocual Field, San Juan Formation, Venezuela
Authors: Guaiquirian L. , Gonzalez P. , Gonzalez A. , Hernandez M. Manuela , Le Maux T. , Mattioni L. , Rouvroy P.
Published: December 2007

Orocual field is an anticline located in the East of Venezuela within El Furrial Trend. The San Juan Formation, a tight Late Cretaceous-Early Paleocene sandstone, is one of the best producing reservoir of Orocual. Located at a depth of about 14000 feet, it is characterised by a low matrix porosity (5 to 6%) and permeability (below 5 mD in average). Very quickly identified as a possible fractured reservoir due to the difference between producers' performance and petrophysical data, this hypothesis was later confirmed with the acquisition of cores and borehole image logs ‘BHI’. Both show the presence of numerous open or partially open tectonic fractures.

The present paper focuses on one of the four structurally compartmentalized fault blocks of the field that presents the highest potential of reserves. It is shown how all available data, geology (Bore Hole Image logs, cores and wireline logs), geophysics, and reservoir engineering data (production data, flowmeters, welltests) were combined to identify the main types of fractures, to predict their occurrence in the reservoir and to determine the hydraulic properties of the different fractures sets. The DFN approach was used to characterise the natural fractures at well scale and to model the full field 3D fracture network. From BHI and core analysis, it was found that the formation Vshale and the porosity were the main geological drivers on natural joints (small scale fractures) occurrence. Those properties associated to the matrix were used to populate in 3D the fracture network model. A second type of fractures, large scale fractures associated to faults, although not identified on wells but strongly suspected to exist, have also been included in the 3D model. The model was hydraulically calibrated first through simulation of a measured flowmeter log with the DFN model and then through match of the KH measured from transient welltests with the KH derived from the model.

The outcome of the study is a reliable set of fracture properties that can directly be used in the 3D simulation model in order to improve the current history match and evaluate injection scenarios for the future.
A Field Development Strategy: When a Simple Stochastic Model Surpasses Numerical Simulation
Authors: Sancho V. , Berrios V. , Gulino F. , Oquendo O.
Published: December 2007

Numerical simulation of reservoirs is one of the most important engineering tools in monitoring mature fields, but depending on the precision and heterogeneity of the data, it can be replaced with an analysis based on statistics and production management.

Señal Picada field, located in The Naquin Province, Argentina, was discovered in 1963. It produced by primary recovery with an almost null declination for more than 12 years. After that, a disorganized secondary recovery process started in 1976, which increased substantially the water cut, due to an early waterfront irruption. In 2002, a reservoir numerical simulator was developed just for an isolated block that contained the 30% of the total reserves of the oilfield.

Due to the uncertainty generated by the quantity and quality of the historical data, the possibility of extrapolate the results of the simulator to another areas was evaluated versus other techniques. In a scenario of high oil prices, it is quite important to have no delays in implementing field development activities. Here is where the choice of one or another methodology can make an economical difference.

All uncertainties involved in field development through different methodologies, such as water conformance, Pattern Injection modifications, etc., can be minimized by the analysis of production data and statistical reserves analysis, combined with an analytical simulation. This allows a plan for recovery reserves faster than the construction of a numerical simulation model.

In the case of Señal Picada, due to the heterogeneity of the data, an accurate simulation of the entire reservoir would take a long time. The use of statistics and production data analysis guided by the analytical simulation has offered an accurate overview of the field behavior. Complementing this evaluation with the results of the numerical simulator, it will accelerate incremental oil production, maximizing the field internal rate of return.
Pore-Scale Characterization and Productivity Analysis by Integration of NMR and Openhole Logs–A Verification Study
Authors: Galarza Tania , Giordano Sergio , Fontanarosa Michael , Saubidet Marcelo , Altunbay Mehmet , Saavedra Benito , Romero Pedro
Published: December 2007

Presently, NMR logs are routinely used to estimate the irreducible portion of the bulk volume of wetting phase (BVI), permeability and the type of hydrocarbons present when filtrate invasion is limited or non-existent. In most cases, the rest of the pore-scale information contained in NMR log data is overlooked or ignored as the model equations used to infer it are empirical in nature. Our aim in this study is to demonstrate the use of and the degree of accuracy of porescale data derived from NMR logs by presenting an actual case study with production test results and comparison to corebased information. This study also demonstrates the importance of NMR based pore-scale characterization if or when the filtrate invasion limits the hydrocarbon typing capabilities.

Pore scale characterization is obtained by transforming the NMR data to synthetic capillary pressure and evaluating the dynamic properties of the formation in conjunction with the fluids present. The capillary transformation of NMR data is performed based on experimental models. The BVI from this transformation (RBVI) is tested against the conventional T2cutoff based BVI for accuracy and reliability prior to the determination of Swanson-based Swirr, relative permeability transformations and the critical Swirr that can be used for identifying transition zone. T2cutoff independent BVI (from which Swirr is derived), threshold pressure, mean pore-throat radius, effective permeability to wetting and non-wetting phases and the md-ft evaluation of subject intervals are the end products of this study. The results are compared to production test data to demonstrate the utility of NMR logs both to production/completion engineering and to well/formation economics.
R Sand Production in an Oil Field of Eastern Venezuela Basin: Example of Change in the Operation Strategy in a Mature Field Reactivation
Authors: Bellorin William , Castillo José , Lopez Sonia , Riera Ladimier
Published: December 2007

The study area has produced over 457 MMBbl of oil since its discovery in 1954. This study is focused on the R sand reservoir, one of the most important of the area. The original oil in place (OOIP) is 140 MMBbls and before the begining of the project, the accounted recovery of OOIP was 7.2%.

The field reactivation was performed after a thorough analysis that included a geological model review and creating a numeric simulation model. This resulted in an increment of the field production which reached up to 7000 Bbls/d of oil and an enhanced recovery factor of 13.6% by March 31st, 2005.

The main producing zone of the study area comprises Early to Mid Miocene (Oficina Formation); it is interpreted as interbedded sandstone, deposited in a fluvial environment with marine to shallow marine influence. Core analysis in one well shows that R sand was deposited in coastal plain influenced by tides and characterized by connected channels and outlets. The 3D seismic information available in the area made it possible to accurately define the structural model. After defining the static model and with the support of the engineering study, the reservoir development plan could be defined, which was oriented to improve and to increase the field productivity. It mainly consisted in drilling horizontal wells where succesful results were obtained after drilling and completing seven wells. This shows the impact of this type of wells in terms of economic benefits resulting in an increment in production and the recovery factor.
Impact of Pressure Depletion on Oil Recovery in Naturally Fractured Reservoirs
Authors: Chacon Abel , Tiab Djebbar
Published: December 2007

In naturally fractured reservoirs (NFRs), current analyses for quantifying reserves based on the material balance equation (MBE) assume that fractured reservoirs behave similar to homogeneous reservoirs, which implies that the fracture and matrix pore volume compressibilities are equal. There is considerable evidence that such assumption is not always valid leading to wrong estimation of reserves. In order to overcome this deficiency a complete treatment of the material balance formulation for naturally fractured reservoirs is presented. The proposed general MBE takes into account the fact that fracture and matrix pore volume compressibilities are different. This equation is used to investigate the impact of pressure depletion on the estimation of oil in place and recovery factors.

As results of this study, new equations to compute hydrocarbons originally in place in NFRs are developed for undersaturated and saturated reservoirs. New plotting schemes for the MBE involving the storage capacity ratio at initial reservoir conditions of fracture and matrix pore volume compressibilities are proposed. The capacity ratio is computed from pressure transient test performed during the early stages of production. These new plotting schemes requires only one regression parameter, the slope of a straight line passing through the origin on a Cartesian plot, which reduces the uncertainty that traditionally two regression parameters (intercept and slope) introduces; as consequence, better estimation of oil in place with fewer historical production data can be obtained. This new method is illustrated by several field examples.

It is concluded that (a) the proposed material balance formulation gives better estimation of oil in place than the traditional MBE computations; (b) the split of hydrocarbons originally in place between fracture and matrix frames depends upon the storage capacity ratio at initial reservoir conditions and; (c) the impact of pressure depletion on the estimation of reserves and recovery factors in naturally fractured reservoirs is significant.