bluuebunny/crossref_metadata_2025 huggingface dataset:
Static and Dynamic Evaluation of Calcium Carbonate Scale Formation and Inhibition
Authors: Kohler N. , Courbin G. , Ropital F.
Published: December 2007

Calcium carbonate scale formation is a major drawback in oil or gas production wells, in geothermal processing equipments and in industrial cooling water installations. In most cases it reduces the overall fluid flow rate, induces formation or production damage and may lead to a shutdown of exploiting operations.

Various chemical inhibitors have been proposed to inhibit scale deposits. A major challenge is the evaluation of their action in near real operating conditions. Usually effectiveness is evaluated by the analysis of residual scale inhibitor in brines.

A novel approach is here proposed which uses an electrochemical technique to accelerate scale formation. Measurements on an electrode immersed in the tested water include as a function of time the decrease of the incident current (chronoamperometry) and the simultaneous increase of the weight recorded by a microbalance (chronoelectro-gravimetry) as a consequence of the progressive electrode surface coverage by scale deposit. By using a specific experimental device it is possible to follow and visualize in situ scale deposition or inhibition on a metallic surface under near-real hydrodynamic flow conditions.
A New Biopolymer-Free, Low Solids, High Density Reservoir Drilling Fluid
Authors: Horton Robert L. , Dobson James W. , Tresco Kim O. , Knox Dave A. , Green Taylor C. , Foxenberg William E.
Published: December 2007

A new reservoir drilling fluid system utilizes a nonbiopolymer, acid- or enzyme-soluble polymer that serves both as viscosifier and fluid-loss additive when combined with activated magnesium oxide and a divalent-cation-based brine. The new fluid shows a unique shear-thinning rheological profile featuring relatively low, high-shear-rate viscosity along with relatively high, low-shear-rate viscosity. This behavior is highly unusual in high-density, brine-based reservoir drilling fluids. A result of this behavior is that effective hole cleaning is provided without generating excessive high-shear-rate viscosities that lead to disproportionate equivalent circulating densities. The new fluid system is based on the higher density, divalent-cation-containing brines (utilizing CaCl2, CaBr2, CaCl2 / CaBr2, ZnBr2 / CaBr2 and ZnBr2 /CaBr2 / CaCl2) in the 11.5 to 17.5 lb/gal density range. The total amount of the sized CaCO3 bridging particles is kept relatively low, 13 to 35 lb/bbl, so that thin, chemically removable filter cakes are produced. The size distribution of these bridging particles is designed according to the ideal packing sequence for optimizing sealing and producing a minimally invading (well productivity enhancing) fluid.
Filtrate Invasion, Barite "Sag" and Grain Crushing by Cutter Impact -- Experimental Wellbore Damage
Authors: Crossley R. , Essone J-Y. Essiane , Wubben Ton , Graas G. van
Published: December 2007

Barite "sag" is known to reduce drilling performance. This experimental study, which used full scale coring bits on large sandstone blocks, shows that the recrushed barite and cuttings can be smeared on the borehole wall to create a low permeability coating. In at least one mud type this coating may be difficult to remove. Drilling fluids are often tailored to block anticipated pore throat distributions with components that can be removed during clean up. In these experiments the grains lining the wellbore were shattered by cutter impacts to a depth of up to 2 mm. This changed the pore throat size distributions in this thin zone, and crushed grain debris was a major component blocking pore throats in this zone. If these factors apply in the subsurface, then drilling fluid may not behave as planned during spurt loss, and successfull clean up may prove more difficult than anticipated. Depth of filtrate invasion is known to be controlled in part by formation permeability, by degree of static mud weight overpressure and by drilling fluid perfomance. In this study, the duration of dynamic interactions between bit, rock and mud is an additional control on filtrate invasion. This suggests that petrophysical analyses of log responses should not ignore ROP.
Disproportionate Permeability Reduction Due to Polymer Adsorption Entanglement
Authors: Al-Sharji H. H. , Grattoni C. A. , Dawe R. A , Zimmerman R. W.
Published: December 2007

Polymers in the form of either solutions or gels are being used to control water production, especially when oil bearing and water zones cannot be isolated. Results of field treatments have varied widely, but often no obvious reason can be given for the success or the failure of the treatment. The lack of understanding of the basic mechanisms by which polymers influence the flow of water and oil hinders a wider application of this process. The achievement of a disproportionate permeability reduction (DPR - reducing the water permeability while producing minimum reduction in the oil permeability) is crucial, and several mechanisms have been proposed to explain this effect. Among those mechanisms, polymer adsorption and lubrication effect are being thought as the main reason for DPR when polymers (without cross-linker) are used.

This paper presents a mechanistic study of the effect of polymer injection on single and two-phase flow. Experiments have been performed in glass micromodels, under both water-wet and oil-wet conditions. The oil and water end-point permeabilities have been obtained, before and after the injection of a cationic polyacrylamide, while observing the fluid distribution and flow patterns. During polymer injection, under water-wet conditions, polymer layers were seen to form and build-up on the crevices between the grains. This mechanism is known as adsorption-entanglement. Data on this phenomenon are scarce, and this paper presents the first visualization study of this phenomenon in porous media.

In water-wet models there was a significant permeability reduction to water, while there was no significant reduction in oil permeability. The entanglement of polymer reduces the area available for water to flow, whereas the oil, occupying the centre of the larger pores, was nearly unaffected by the polymer entanglement. In oil-wet models, where polymer layers were not observed, the oil and water effective permeability before and after polymer injection remained unchanged. Our results confirm that adsorption-entanglement for water-wet media, which produces the build-up of the polymer layers on the grain crevices, is a basic mechanism by which polymers can modify the flow characteristics and thus preferentially reduce the water relative permeability.
In-Depth Filtration of Macromolecules Induced by Bridging Adsorption in Porous Media
Authors: Zitha Pacelli L. J.
Published: December 2007

Previously, we developed a microscopic model for the bridging adsorption of flexible chains, during non-inertial flow of polymer solutions through granular porous media. Owing to its local character, that model does not take into account the filtration of the largest polymer molecules, while this filtration appears to be one of the essential features of bridging adsorption, from both fundamental and practical standpoints. During polymer placement for water control, for instance, polymer propagates over distances of several inches enabling filtration of polymer to take place.

In this paper, we develop a macroscopic model for layer and bridging adsorption during polymer flow through porous media. Our emphasis is on the filtration of the largest chains induced by bridging adsorption. In order to describe this effect, we introduce for the first time a space and time dependent probability (or fraction) of the largest chains. Our model condenses in a non-linear system of four partial differential equations describing polymer and the largest mass conservation and layer and bridging adsorption kinetics. The model appears to be relevant, beyond the description of bridging adsorption, to several in-depth filtration processes induced by flow and retention.

By physical arguments based upon previous experimental observations, we reduce the general equations to a simpler formulation for which we were able to derive an approximate analytical solution. We prove that, in one simple case, the concentration and the bridging adsorption probability profiles in the core decrease exponentially as a function of the distance from core inlet. The influence of the determinant parameters (velocity gradient, adsorption energy, etc.) is discussed. We show that the model is in good agreement with previous experiments conducted under well-controlled conditions.
Prediction of Polymer Viscosity Reduction in Pores Using an Exact Depletion Profile
Authors: Zitha Pacelli L. J.
Published: December 2007

The modeling and numerical simulation of processes such as polymer placement for water control, fluid loss control during drilling, polymer based chemical flooding and the interpretation of the related laboratory studies need a correct quantification of the apparent viscosity of polymers in porous media.

Past experimental and theoretical studies have shown that, in the absence of adsorption, the viscosity of polymer solutions decreases in porous media due to polymer depletion near pore walls. The proposed models considered pores that are relatively large with respect to the thickness of the depletion zones and assumed Newtonian flow. The two fluid model, in particular, is based on a discontinuous concentration profile. These characteristics give rise to limitations in the estimation of the apparent viscosity in porous media with very small pores.

In this paper we provide new insights on the depletion effect and develop a new model for the apparent viscosity, taking into account an exact polymer depletion concentration profile and the Non-Newtonian character of the polymer solutions. In this way we are able to predict the lowering of the apparent viscosity in pores over entire ranges of pore radii. Using analytical and numerical hydrodynamic calculations, we investigate the influence of the parameters (polymer concentration, ratio between the thickness of the depletion layer and effective pore radius, velocity gradient, etc.). Model predictions are found to be in good agreement with experiments available in the literature.
Disproportionate Permeability Reduction when a Silicate Gel is Formed In-Situ to Control Water Production
Authors: Grattoni C. A. , Jing X. D. , Zimmerman R. W.
Published: December 2007

Water production from oil and gas reservoirs is increasing world-wide, as more reservoirs are becoming mature. In order to control water production, polymers or gels are injected into production wells to either block the flow, or to reduce water permeability. In the latter case the polymers/gels are known as relative permeability modifiers. In these treatments, a gel is often formed in-situ through a chemical reaction, creating a semi-solid material that is capable of modifying the permeability.

To visualise the processes that occur during the flow of water and oil through a porous rock containing gel, experiments were conducted in transparent glass models in which the flow events can be observed. To form the gel in-situ, a novel alkyl silicate gelant was used, which is soluble in the oil phase, and which, when in contact with water, reacts to convert the water phase into a gel. From the flow observations, the underlying physics can be extracted and the basic mechanisms understood (reduction in effective pore size distribution, gel-bounded water, wetting films of free water, etc.). These mechanisms were used to develop a conceptual model, which consists of three main elements: pore space (bundle of capillary tubes), occupancy of the phases (fluid and gel distribution), and flow equations.

The output from the conceptual model is the capillary pressure as a function of total water saturation and end-point relative permeability. The results from this model successfully represent the disproportionate permeability reduction observed in micromodels and core experiments, verifying the mechanisms included in the model. This model may be quickly and easily used to study the influence of pore size distribution, gelant concentration, and initial water saturation, before undertaking laboratory or more complex modelling studies.
A Fractal Model for the Vertical Distribution of Sands in the Perales Oil Fields in the Basin of Golfo San Jorge (Argentina)
Authors: Hlebszevitsch Julio C. , Breda Eduardo
Published: December 2007

The irregularity and discontinuity that the sands present in the vertical sections of the Bajo Barreal Formation lead us to the concept that these sands present a difficult and chaotic distribution. The tuning effects and lack of resolution of the seismic information leads us on a search for new models and methodologies to find a model for the distribution of these sands. The objective of this work is to demonstrate the fractal behavior of the sets of sands, and the need to keep this property in mind for any type of geostatistical analysis, since these types of analysis generally assume a normal distribution of the data population in opposition of the fractal concept.

The term fractal was first defined in 1975 by Benoit Mandelbrot to describe the geometry of those objects which have an extremely irregular shape, interrupted and fragmented, and continue being so at any scale chosen for study. The fractal dimension (D) allows us to quantify the degree of irregularity of a geometrical set or of a natural object. An important consequence of this scale exponent is that a population of objects that respond to a fractal distribution will not have average values of its properties, being able to speak only of the distribution of sizes, of which a specific object or phenomenon occurs within a specific interval of time or space. An important concept is that the fractal behavior only occurs within a range of scales in nature, and no natural object is indefinitely fractal.

The punctuated behavior of the sedimentation brings, as a consequence, the distribution of the sands presented in a discontinuous form, and for that reason describable from a fractal viewpoint. Based on these observations, there is a need to characterize the population of sands in the Bajo Barreal Formation as a fractal set. Likewise, these results of the subsurface have been verified with data from outcroppings, having obtained similar results. The fractal vision has contributed to the discrimination of parasequences, the recognition of a distribution model of the sands, and the conclusion that the most important problems in these oil fields are the pathways of migration and trapping of hydrocarbons and not the presence of sands as was previously assumed.
Selection of Proper EOR Method for Efficient Matrix Recovery in Naturally Fractured Reservoirs
Authors: Babadagli T.
Published: December 2007

As most of the oil is stored in matrix due to its higher storage capacity than fracture network of naturally fractured reservoirs (NFR), reservoir development plans will aim at maximizing the matrix oil recovery. An enhanced oil recovery (EOR) application principally targets (a) to minimize the residual oil in matrix depleting the matrix as effective as possible and/or (b) to accelerate the recovery rate for rapid production of oil cost efficiently. For reservoirs with high recovery factor, minimizing matrix residual oil saturation is a critical issue to extend the life of the reservoir. For reservoirs with low recovery factor, accelerating the production rate is more vital. For each of these reservoir types, different EOR methods should be considered and implemented accordingly. This paper addresses and discusses these two issues and identifies selection criteria for different EOR methods in NFR, namely chemical (surfactant and polymer) and hot water injection.

The focus is specifically on matrix type (permeability and wettability), oil and water viscosities, matrix boundary conditions, transfer type (co- or counter-current imbibition), and IFT. For the different values of these properties, the most proper injection fluid type to be used as an EOR fluid is identified to obtain an effective matrix recovery. Co-current and counter-current capillary imbibition experiments at static conditions are conducted to show how effective and how useful these applications are for different rock and fluid types and matrix boundary conditions. For experimentation, strongly water wet Berea Sandstones and oil-wet carbonates (cores from an oil formation) are used. Light crude oil, kerosene and engine oil are selected as the oleic phase.

Proper project implementation (adjustment of injection rate and/or concentrations) and selection of the injection fluid for a cost efficient management are also discussed for different conditions outlined above. Finally, the selection criteria of EOR methods based on the rock and fluid properties are defined. This will provide an insight into an effective management of NFRs and reservoir depletion strategies, if the matrix oil recovery is the main target.
High-resolution Sequence Stratigraphy and Reservoir Characterization Applied to Mature Fields: Example from Eastern Venezuela Basin
Authors: Picarelli Andre , Holder Bruce , Arguello Jorge , Peron Renato , Nieves Israel , Rojas José
Published: December 2007

The Mata-Araibel Concession (Eastern Venezuela Basin – Mata 3, Mata 16, Mata 19, Mata 20, Mata 14, Mata 7 and Zorro Fields-) records Miocene shallow-marine sedimentation in the distal zone of the foreland basin, which was formed by the eastward migration of the Caribbean Plate in oblique convergence with the South American Plate. This work aims to integrate high-resolution sequence stratigraphy with historical production data to optimize production in this mature area, through the reactivation of abandoned reservoirs and the definition of flow units to implement secondary recovery projects. The shallow marine paleophysiography in a ramp setting, distal to the collision front of the foreland, allowed the development of multiple high frequency sequence boundaries within a broad estuarine system. The main reservoir rocks were deposited during 5th order lowstand/transgressive systems tracts, represented by estuarine (channels and tidal bars) and platform (sand ridges) sediments. Isolated transgressive sand ridges and tidal bars encased in estuarine mud constitute the main targets for by-passed oil. Higher frequency (4th and 5th order) erosional surfaces within 3rd order lowstand/transgressive systems tracts and minor extensional faulting allowed communication among different reservoirs. Based on this communication, simultaneous development of (formerly) different reservoirs is possible through the identification of hydraulic flow units. A volumetric review of each stratigraphical unit, the reallocation of the production records to appropriate units and the analysis of pressure as a function of recovery factor were completed. The results of this work, supplemented with newly acquired data, indicated the entire Oficina L sand package may be considered as one hydraulic unit (historically, the L sands in Mata were produced as 12 discrete reservoirs). Similar conclusions were reached for the Oficina S and U (Oficina and Merecure) sand packages. Additional studies have been undertaken to identify the existence of other hydraulic units as already shown in the Oritupano Area, also operated by Perez Companc SA(1). Mata wells are deep and expensive to drill or recomplete. The economic viability of producing this mature field will be greatly enhanced by allowing commingled production from identified and proven hydraulic units and from a set of reservoirs which proven to be economically unviable under individual production scheme.(2).
Application of New Generation Large Roller-Cone Bits Reduces Drilling Costs in Eastern Venezuela
Authors: Carre Leandro , McCoy Rick , Wilson Larry , Drilling Cliffs , Cockerham Jerry , Grimes Bobby , Anderson Mark , Pardo Nesny
Published: December 2007

An analysis of recent run data from two fields in Eastern Venezuela documents large metal seal bearing roller cone bits (16″ & 17–1/2"), with a new generation steel tooth cutting structure, can be used for a much greater number of total bit revolutions than prior generation bits. The new generation metal seal has proven its ability to significantly extend bearing life and reliability and thereby provide significant reductions in drilling costs. Penetration rates have more than doubled with total footage up 89% in some instances, with less overall cutting structure wear. Cost savings of up to $121,000 US per well have been documented.

The authors will describe the application of these new bits and present case studies that document significant performance improvement in the Santa Barbara and Mulata fields of Eastern Venezuela. They will also describe the development of the latest generation metal sealed bearing package and the metallurgical and design improvements of the new steel tooth cutting structures.
Physical and Economic Feasibility of Waterflooding of Low-Pressure Gas Reservoirs
Authors: Valjak M. , Novakovic D. , Bassiouni Z.
Published: December 2007

A volumetric gas reservoir reaches its economic limit when the reservoir pressure falls below the level needed to sustain the surface pressure necessary to move the gas through surface facilities and into a pipeline. Compression is considered when economically feasible. Waterflooding of low-pressure gas reservoirs is viable alternative to compression. Waterflooding reserves may in certain cases exceed that of compression. Water displaces gas efficiently because of extremely favorable mobility of low-pressure gas. The incremental recovery depends on the initial reservoir pressure and the pressure at which the waterflooding is implemented. This management option may also be used in conjunction with compression to maintain reservoir pressure, which ensures well unloading, and reduces need for well workover.

The economic feasibility of waterflooding depleted gas reservoirs is controlled by the amount of water needed, which is high because of the high gas compressibility. The amount of needed water increases dramatically as the reservoir pressure decreases. Managing this option as a water disposal for the field or nearby fields would be a major additional economic incentive. The injection is not a major cost component, as the water hydraulic head would exceed the reservoir pressure in most cases.

The cost of water injection can be eliminated altogether by downhole commingling of high pressure large aquifer with the depleted gas reservoir. This option would require special but simple downhole completion. Water volume supplied by the aquifer can be monitored using reservoir pressure and production data.

Studies of actual reservoirs demonstrated the technical and economic feasibility of this management option.
Extra-Heavy Crude Oil Downhole Upgrading Process Using Hydrogen Donors under Steam Injection Conditions
Authors: Ovalles Cesar , Vallejos Carlos , Vásquez Tito , Martinis Jorge , Perez-Perez Alfredo , Cotte Edgar , Castellanos Luis , Rodríguez Héctor
Published: December 2007

An extra-heavy crude oil underground upgrading process is described which involves the downhole addition of a hydrogen donor additive (tetralin) under steam injection conditions. Using a batch laboratory reactor or a continuous bench scale plant (280-315°C and residence times between 24-64 h), physical simulation experiments showed an increase of at least 3° in API gravity of the treated Extra-Heavy Crude Oil, three-fold viscosity reduction and, approximately, 8% decrease in the asphaltene content with respect to the original crude. It was found that the presence of the natural formation (catalyst) and methane (natural gas) is necessary to enhance the properties of the upgraded crude oil. Compositional-thermal numerical simulations were carried out and the results showed a good match between the calculated and experimental °API gravities of the upgraded crude oil (average relative error 1-4%) for all conditions studied. Similar results were obtained with the asphaltene contents (14-23%), percentage of conversion of the >500°C fraction (12%) and tetralin (16-23%).
Progressing Cavity Pump Pattern Recognition in Heavy and Extra-Heavy Oil Cold Production
Authors: Ocanto Leonardo , Rojas Alexander
Published: December 2007

The large heavy oil reserves discovered in the Orinoco Belt, in Eastern Venezuela during the last ten years lead to a growing interest to raise the level of the technology used to support the exploitation of heavy and extra-heavy oil reservoirs, due to the complexity of such processes. To obtain the most of the reservoir while maintaining equipment working at top performance conditions, the use of Progressing Cavity Pumping (PCP), along with extensive use of emerging technologies for process monitoring and analysis, has proven to be a valuable tool to protect for formation damage while successfully increasing productivity.

Being Progressing Cavity pumping behavior a very complex issue, due to the inextricability of its operation (system kinematics difficult to model explicitly, interaction of elastomer with lifted fluid, among others), the use of Artificial Intelligence (AI), particularly in identifying operation and fault patterns, can be a powerful tool to gain insight of heavy and extra-heavy production processes. Some considerations regarding the use of these techniques are presented.
Analysis of a Successful Cyclic Steam Process at Cymric Field, California
Authors: Fong W. S. , Lederhos L. , Skow L. A. , Evola G. M. , Choi J.
Published: December 2007

A successful cyclic steam project has been implemented by Chevron USA Production Company in the Antelope Shale Formation of the Cymric 1Y Field, California. Recovery is expected to exceed 50% OOIP from this low permeability, heavy oil diatomite reservoir. The expected high recovery will be achieved through aggressive infill drilling, optimization of current steam injection operations, and favorable interaction of steam with induced fractures.

The patented cyclic steam process induces fractures by injecting steam at pressures exceeding the reservoir fracture gradient. Small, controlled injection/production cycles are applied to maximize steam efficiency. Optimizing cyclic operations in over 400 wells, which are, on average, cycled more than once per month, is a formidable task.

To follow is a description of two very different approaches for predicting and optimizing the performance of the cyclic steam process: (1) use of a very detailed, multiple-pattern simulation model, and (2) use of Design of Experiment techniques (DOE) coupled with much simpler, single-well simulation models.

While the detailed simulation model was able to capture complex operational history and provided a good history match, its use was limited due to long run times. Consequently, sensitivities to various key uncertainties are time consuming to obtain, limiting the flexibility of this approach. The DOE approach allows us to study more reservoirs and operational parameters in a relatively short time. Results from both approaches were combined to analyze and forecast field performance, and for aiding reservoir development decisions. Our combination method represents an optimal approach for cyclic thermal recovery process evaluation in heavy oil diatomite reservoirs.
A Coupled Reservoir-Geomechanics Model and Applications to Wellbore Stability and Sand Prediction
Authors: Wang Yarlong , Lu Baoping
Published: December 2007

Sand production and open hole collapse during production have been a great concern for production engineer, as the detrimental consequences are often associated to a desirable high production. Sand production usually occurs under a high-pressure gradient in poorly cemented formations. Whereas wellbore collapses could occur if a bottom hole pressure is below a certain level or production reaches a certain rate, i.e. during underbalanced drilling, under a high rate production, or when an aggressive well completion for high production is used. To determine the critical flow rate or bottom hole pressure, a coupled reservoir-geomechanics model is developed to simulate the interaction between reservoir flow and deformation. The model is developed and implemented numerically in Finite Element method by fully coupling a comprehensive geomechanics model to a three-phase reservoir behavior model. Gas component behavior is only considered below a bubble point, and it remains inside the oil phase before a critical gas saturation can be reached in our simulations. The effects of multiphase behavior on near well stresses and deformations, including high compressible gas component in the solution gas phase (foamy oil) are analyzed. Both Mohr-Coulomb and Drucker-Prager criteria are introduced to outline the plastic yielding surface and to govern the plastic flow. The effects of the stress-dependent formation moduli and permeability changes are permissible. The final stability and the onset of sand production are determined by a critical effective plastic strain and zero effective radial stress, whichever condition occurs first. Our studies indicate that, other than the well known factors such as bottomhole pressure and drawdonw, well stability and sanding risks are critically controlled by (1) the solution-gas behavior, (2) the formation stiffness, and (3) the residual cohesion. The latter can be senstitive to the wetting phase saturation. Considering production enhancement and formation damage, the reservoir porosity increase due to formation dilation is simulated, which can generate a negative skin near a well and result in a production enhancement. Our model can be used to calculate both the enhanced production and the ranges of the enhanced zone.
Sand Handling During Multiphase Operations With Twin-Screw Pumps
Authors: Dorenbos Cornelis (Kees) , Müeller-Link Dietrich , Jäeschke Axel
Published: December 2007

It is sure that production equipment has to handle solids, which are released from the reservoir rock during hydrocarbon extraction. Subsequently it is necessary to define all operational consequences and circumstances at an early project stage. But solids released during well intervention operations or disposal of any kind of fluid through the flowlines strictly have to be avoided or taken care of by special actions. This is especially true when rotating equipment such as twin-screw multiphase pumps are part of the downstream production train.

Operation parameters mostly influencing the wear, such as axial fluid velocities and product viscosity are outlined. The wear pattern due to erosion as well as abrasion occurring in Multiphase Pumps with its effect on boosting operations is described. Increasing suction pressure and pump temperature definitely are a sign for a decreasing capacity of the pump so that production forecast can not be met any longer. Excessive leakage from the mechanical seals are another one.

Preventive measures are to be taken in case of solids transport anticipated. Material selection, but moreover surface treatment of the effected pump internals offer a variety of chances to reduce the wear.

But neither can such wear be excluded nor avoided as it is the same for any other equipment used in such environment.

Special attention is given to the mechanical seals, whose wear sometimes can stop operations immediately. Different material selections for this equipment seldom offers improvement, and may even lead to a worse situation.

Equipment used to filter the fluid stream can be used. It is necessary to design them for multiphase flow with sometimes severe slugging to occur. Strainers (at least temporary) are a must after any work on the flowlines to the pump.

Examples from field installations will finalise this paper outlining the experience gained under a variety of operating parameters, surface treatments, mechanical seal arrangements, and filtering equipment
Contribution of Horizontal-Well Log and Pressure Data in Stochastic Modeling
Authors: Aissaoui Karim , Tiab Djebbar
Published: December 2007

In heterogeneous reservoirs like Hassi Messaoud, the exact interwell location of each reservoir sandstone body can not be in most cases easily located, and the potential of drilling unsuccessful production wells is usually present. In this situation a reservoir characterization model with usable uncertainties is needed.

Conventional modeling techniques fail to quantify heterogeneities in lateral direction, however horiontal well data appear to compensate for this lack of information, providing some knowledge about variability of reservoir parameters, using data recorded along the horizontal drainhole of horizontal wells, hence providing adequate measurements of reservoir properties in the interwell locations.

In this study a petrophysical model was generated for the north east area of Hassi Messaoud field comprising four horizontal wells. The generated models of porosity permeability and shale distribution were in agreement with Hassi Messaoud braided fluvial depositional model. The facies lateral variations have confirmed the nonuniform depletion throughout this sector of the field, which has led to its zonation.

Once the reservoir characterization was complete, the generated model was validated using a full-field model of North East area`, that involves history match of each well individually.
New View on Continuous-Removal Liquids from Gas Wells
Authors: Li Min , Lei Sun , Li Shilun
Published: December 2007

To prevent gas wells from load-up, it is necessary to study the cause of load-up and condition for liquids to accumulate in wellbore. The paper adopts the view that the liquids droplets entrained in gas wells tend to be flat shape and deduce new formulae for continuous removal liquid from gas wells. The results calculated from the formulae are smaller than that of conventional Turner's. However, the predicted results accord with practical situation of gas wells in China gas fields. In addition, for the easier application purpose, the paper put forward simple formulae from the deduced formulae under analyzing different factors affecting removal liquids from gas wells. The model explains why many gas wells produce without load-up when the producing rate is by far smaller than that of Turner's minimum producing rate. In order to help engineer working in gas fields judge load-up effluence on gas well production, the paper analyzes the production performance of load-up and near load-up as well as unloading gas wells through wellhead producing performance figures.
Design and Performance of Miscible Flood Displacement
Authors: Laieb Krimo , Tiab Djebbar
Published: December 2007

Oil recovery by miscible gas injection process has been a topic of research, development, and field testing for more than 40 years. There is still some disagreement in the interpretation of laboratory, field-test data and selection of predictive methods. Field experiments, however, have disclosed a number of problems with hydrocarbon miscible flooding that limit the oil recovery and diminish the economic attractiveness of these processes. Due to the fact that there is no generalized engineering method or model that adequately accounts for all the factors, each model tends to emphasize one or more aspects of the displacement while neglecting other aspects for the sake of tractability.

A parametric study is done, using a 3-D, compositional numerical simulator "VIP" in order to design the model and analyze the results and performance of miscible gas injection in Hassi Berkine South field. A 9-component PR EOS was used to describe the phase behavior using IMPES formulation. The process of simulation study to design and optimize the full field model included the following steps: Start with a basic run, used as a reference case.Compare the base case (miscible gas injection) with water injection process.Consider the phase behavior effect.The reservoir description effect.Vertical sweep out.Partial recovery of miscible flood.Influence of grid variation.

A cross sectional model was used to represent the simulation domain that covered about 5000 ft² in area and 100 ft in thickness. All the runs consisted of two wells, penetrating the entire layers, the injector in the first cell and the producer in the last one.

From the results it has been concluded that the use of horizontal well data has compensated for lack of information about reservoir heterogeneity in lateral direction of the interwell locations.
South Wasson Clear Fork Reservoir Model: Outcrop to Subsurface via Rock-Fabric Method
Authors: Lucia F. J. , Jennings J. W. , Ruppel S. C.
Published: December 2007

South Wasson Clear Fork field produces from two reservoirs, the middle Clear Fork, with a seal located within the upper Clear Fork Formation, and the lower Clear Fork, with a seal located in the Tubb Formation. Six sequences have been defined on the basis of facies succession, seismic interpretation, and outcrop analog studies in Apache Canyon, Sierra Diablo Mountains, West Texas. Rock-fabric/petrophysical studies have shown that a single porosity-permeability transform and porosity-saturation-capillary-pressure model can be used to calculate permeability and water saturation in uncored wells. Five rock fabrics have been described, and all plot in the petrophysical class 1 field. This surprising result is related to the presence of large volumes of poikilotopic anhydrite, which reduces porosity but has little effect on pore size or perme-ability. Permeability values calculated from porosity logs are distributed in the interwell environment within a high-frequency-cycle (HFC) stratigraphic framework. Analog outcrop studies demonstrate that the Clear Fork Formation can be characterized by upward shallowing (HFC’s). Identifying HFC’s, however, is made difficult because of the high uranium content of the Clear Fork and the lack of a relationship between water saturation and rock fabric. A statistical relationship between porosity and rock fabric is developed, however, that allows porosity to be used as a surrogate for rock fabric, and vertical increases in porosity are interpreted as mud-dominated to grain-dominated fabric successions and used to define HFC’s. The HFC’s are divided into two rock-fabric flow layers, an upper, grain-dominated and a lower, mud-dominated layer, in order to preserve high-and low-permeability intervals. Permeability data from the outcrop analog in Apache Canyon are used to demonstrate that the vertical variability seen in the log calculations within the rock-fabric flow units does not represent permeable strata but is statistical variability at a near-random scale.
Reservoir Zonation in the Barnhart Field: Ellenburger Group, Ozona Uplift, Reagan County, Texas
Authors: Hunt Tim J.
Published: December 2007

Barnhart Field was discovered in 1941 on the Ozona Uplift, southeastern Reagan County, Texas. The field produces from the Ellenburger Group on approximately 10,000 acres that can be divided into a southern part on University Lands and a northern part on private land. Two pilot waterfloods were attempted; neither was successful. The field was essentially abandoned in 1976 after producing more that 16 million BO. The structure of the field is an asymmetrical anticline trending northeast – southwest with the crest on the northern part of the field. Structure alone does not appear to control production because the southern part produced slightly more oil than the northern part. Insoluble residue analyses and lateral-log correlations indicate the Ellenburger in the northern part of the field was more deeply eroded than in the southern part. The Ellenburger Group, in this field, can be divided into three pay zones, the Upper Honeycut, the Lower Honeycut and the Gorman. The Upper Honeycut produces only in the southern part of the field and may have the best developed porosity in coarse crystalline dolomite. An isopach of the Honeycut pay zones shows fair agreement between thickness and production. The Gorman pay zone does not correlate well indicating that production cannot be explained by gross isopachs alone.
Field-Scale Characterization of Permeability and Saturation Distribution Using Partitioning Tracer Tests: The Ranger Field, Texas
Authors: Iliassov Pavel A. , Datta-Gupta Akhil , Vasco D. W.
Published: December 2007

This paper discusses the application of an efficient streamline-based inversion method to a large multi-well multi-tracer Partitioning Interwell Tracer Test (PITT) in the McClesky sandstone, Ranger Field, Texas, to characterize both permeability and oil saturation distribution. During a typical PITT, a conservative and a partitioning tracer are injected into the reservoir. The partitioning tracer gets partially absorbed into the oil phase, leading to a separation in the tracer responses that can be used to infer oil saturation distribution in the tracer-swept area. Our approach is extremely efficient because it relies on analytic computation of the sensitivity of the tracer response to reservoir parameters such as permeability and saturation using a single streamline simulation. We follow a two step procedure whereby we first match the conservative tracer response to determine the permeability distribution and then match the partitioning tracer response to obtain oil saturation distribution in the reservoir. The entire history matching took less than 6 hours in a PC as opposed to several months typically required for a manual history matching.

We compared our results to a manual history match obtained using a finite-difference simulator. Both the manual history matching and the streamline-based inversion identified similar large-scale trends in permeability and saturation distribution. However, well-specific matches were significantly improved over those obtained through the manual history matching. Our approach is much more efficient in terms of computation time and effort and the results are less sensitive to personal bias compared to manual history matching. Finally, we discuss a procedure to assess the results in terms of resolution of the estimates of permeability and saturation distribution.
Constraining the Spatial Distribution of Fracture Networks in Naturally Fractured Reservoirs Using Fracture Mechanics and Core Measurements
Authors: Olson Jon E. , Yuan Qiu , Holder Jon , Rijken Peggy
Published: December 2007

Observations of natural fractures in core or image logs typically give limited information on orientation, aperture and intensity. Because of the sparseness of wellbore intersections of fractures, data analysis results in incomplete statistical characterization of the fracture population, leaving interwell characterization almost impossible. Using basic fracture mechanics models and a novel core-testing technique, we propose that the fundamental shape of fracture parameter distributions can be predicted, and that there is a characteristic, quantifiable relationship between fracture length, spacing and aperture. We have performed subcritical fracture growth tests on numerous core samples, using credit card sized specimens, demonstrating the ability to characterize fracture mechanics properties of rock on a bed by bed basis. Using the subcritical index, a parameter that quantifies the relationship between natural fracture propagation velocity and tip loading conditions, we can predict the degree of fracture spacing regularity or clustering for a given reservoir bed. This subcritical parameter, along with information on the number of initial natural flaws in a given rock type, allows us to quantify the expected length distribution of the fractures. Under many conditions, as verified from outcrop data, fracture length is theoretically expected to follow an exponential distribution. Since natural fracture length is typically unobservable in subsurface data, we derive relationships that relate fracture length to aperture and spacing, both more readily measurable quantities. With this information, matrix block size and fracture drainage continuity can be estimated for the purpose of flow simulation in a fractured reservoir.
Drilling with Aerated Drilling Fluid from a Floating Unit Part 2: Drilling the Well
Authors: Lage Antonio C. V. M. , Santos Helio , Silva Paulo R. C.
Published: December 2007

The biggest challenge of the aerated fluid drilling technology development was overcome with the well in Albacora being drilled with the semi-submersible platform Petrobras 17 (P17). A previous paper1 described the stages before the drilling activity: planning, new equipment, rig modifications and all the preparation for drilling the well.

This paper describes the drilling operation itself. All the important points and differences relative to the conventional drilling method are highlighted, with special emphasis to the new equipment installed at the platform: the vertical compact separator, the automatic control system, and the RiserCap™rotating control head. The operation of the new equipment, performance and the problems observed are presented and discussed. The points of improvement are suggested and ways to move forward with this new technology also discussed in the paper.

The present work also addresses the positive impact of this field test relative to the implementation of the light-weight fluids technology from floating units. This initiative has been carried out systematically by Petrobras in the form of a Joint Industry Project (JIP) and has been congregating operators, service companies and consultants. The next steps of this project to use effectively light-weight fluids for drilling in deepwater are discussed. The experienced obtained with this operation was crucial to direct and guide the most important points to be studied and developed in the next phase of the project.