bluuebunny/crossref_metadata_2025 huggingface dataset:
A Pilot for Polymer Flooding of Saertu Formation S II 10-16 in the North of Daqing Oil Field
Authors: Demin Wang , Zhang Zhenhua , Chun Li , Cheng Jiecheng , Du Xingjia , Li Qun
Published: December 2007

Several papers on polymer flooding pilot test in Daqing have been published previously, they stress on enhancing oil recovery by polymer flooding in thick pay zone of major reservoirs with high permeability and heterogeneity. This paper presents the polymer flooding pilot test results in thin layers of non-essential reservoirs with medium-low permeability and heterogeneity. The purpose is to:study the feasibility of polymer flooding in such thin pay zones;test separate injection techniques;provide data for further extending polymer flooding potentials.

The pilot has 4 injectors and 9 producers in inverted five spot patterns. The polymer flooding through Putaohua P I 1–3 formation had been finished in this pilot in 1990, then S II 10–16 was plugged and S II 10–16 was perforated to perform polymer flooding by dual-pipe separate injection. S II 10–16 formation includes 5 sedimentary time units and has complex geometry of sandbody and some layers pinch out in a few wells in the pilot. Its microstructure relief is large, the deference in depth of the formation is 3 7 meters. The net thickness of a single layer is 0.4 to 4.0 meters. Its average permeability is 0.342 m2 and Dykstra-Parson coefficient is 0.6. Polymer injection started in December of 1993 and 0.35 PV of polymer solution has been injected by the end of 1995.

When 0.025 PV polymer solution was injected, the producers responded one after another. The average water cut of the pilot decreased from 94.5% to 80.1% and daily oil production increased from 37 tons to 95 tons maximum. The water cut of the central well decreased from 95.1% to 63.1%, daily oil production increased from 8 tons to 33 tons. Up to now the oil recovery for the central well has increased 10.84% OOIP over water flooding with the polymer flooding efficiency of 151 tons of oil per ton of polymer.

The measurements of injection and production profile showed that the heterogeneity of the reservoir is adjusted and that separate injection technique by dual-pipe is feasible.

P. 431
Revitalization Of A Mature Volatile And Condensate Oil Reservoir Using Horizontal Well
Authors: Villalba S.M. , Perez P. , Marcano C. , Rojas G. , Rodriguez H. , Almeida J.
Published: December 2007

REVITALIZATION OF A MATURE VOLATILE AND CONDENSATE OIL RESERVOIR USING HORIZONTAL WELLS.

The great interest shown in optimizing the exploitation of reservoirs, in the last two decades through the drilling of horizontal wells, has been the best evidence of the potential of this technology. Significant increments in production rates and recoveries have been reported even in oil fields considered uneconomic.

In this paper, the revitalization of the RG-14, COEF reservoir in the Santa Rosa Field by means of horizontal wells is analyzed. This reservoir is the most important mature reservoir producing volatile oil and condensate in Eastern Venezuela. The RG-14, COEF reservoir started its production in April of 1950, having been subjected to gas injection since 1955. Depth of the reservoir varies from 6560 ft subsea at the crest of the dome to 11150 ft at the flank. Presently, gas channeling and the subsequent entrampment of oil in undrained areas limit the recovery of 14.5 MMBls of remaining reserves. Consequently, the drilling of horizontal wells is a potential option to minimize gas channeling and maximize the drainage area, increasing crude production, final recovery and the economic feasibility of the project, at the same time.

This paper presents the integration of geological, reservoir and production studies to define undrained flow units, the selection of objective areas for three horizontal wells, the characterization of fluids, production forecast by means of pseudocompositional simulation and an economic analysis. A Peng-Robinson equation-of-state was used, to characterize both gas condensate and black oil. The simulation studies were performed only in the areas were horizontal wells are proposed, in order to compare them with vertical wells. Results indicate that it is feasible to reactivate production from the RG-14, COEF reservoir in the Santa Rosa Field from the current 567 STBD to a level of 2620 STBD through the drilling of three horizontal wells.

Introduction

In Corpoven's Anaco and San Tome traditional areas in the Eastern Venezuela Basin, there are about 134 mature fields of condensates and medium and light oil which still have reserves of between 50 and 300 million barrels. Secondary recovery processes (gas injection) used in these fields for the last 30 years have permitted the extraction of 75% of the initial estimated reserves. However, a good portion of the remaining reserves are still trapped due to inefficient drainage and preferential channeling of injected gas and/or water in the reservoirs subjected to a pressure maintenance.

Due to these circumstances, the use of the horizontal drilling technology is required in order to maximize the contact with undrained areas and so reduce the water and/or gas coning. Consequently, this procedure will permit the acceleration of the final recovery of reservoirs.

P. 231
Multi-Lateral Underbalanced Drilling For Field Optimization: Weyburn Unit, Saskatchewan, Canada
Authors: Yurkiw F. J. , Gilmour S. G. , Barrenechea P. J. , Wasslen R. D. , Churcher P. L. , Pustanyk R. H.
Published: December 2007

PanCanadian Petroleum Limited, operator of the Weyburn Unit in southeastern Saskatchewan, Canada, has been involved in the development and application of underbalanced and multi-lateral drilling technologies to access reserves which otherwise were likely to be uneconomic to develop. In an attempt to optimize the mature waterflood in the Weyburn field, both vertical and horizontal infill wells have been drilled over the last 12 years. The most success has been realized from horizontal wells, which have evolved from single laterals to dual laterals to quad laterals. The combination of multi-lateral wells and properly designed underbalanced drilling techniques has resulted in increased reservoir access, significant decreases in the cost of reservoir access, and decreased formation damage. Continued exploitation of remaining reserves has been accomplished by progressively pushing the development of new technology to meet the changing economic and technical demands imposed by drilling in different parts of the Unit.
A Comprehensive Study of Wellbore Stability in Shale Formation and Its Application to Horizontal Drilling Operations
Authors: Cheng Yuanfang , Yan Jienian , Wang Guihua
Published: December 2007

Though the mechanical studies of wellbore stability in the water-sensitive shale formations have been conducted for many years, there was almost no successful example of application in drilling operations. The main reason for this is that the in-situ mechanical properties, strength and hydrated stress of shales can not be accurately determined using traditional procedures.

The project focuses on studying the shale strength in different water contents and the changes of hydrated stress in different in-situ stress, hydraulic drop and classification of shales. The shale samples were obtained from S3 group in Oagang Oilfield. On the basis of plenty of multidisciplinary teamwork, the procedures for the comprehensive evaluation of the various properties of the shales, such as the in-situ strength, pore pressure, Yuang's modulus are given by virtue of a series of laboratory test data, log data and drilling information. In addition, a model that can be used to calculate the borehole collapse pressure, fracture pressure and to determine the suitable density of drilling mud is developed according to the theory of elastic mechanics in porous medium and the theory of partial molar free energy. The model is superior to the models provided in the past in the accuracy of prediction because its input parameters were synthetically identified with test data, log data and drilling information, and both the influences of drilling muds on the shale properties and hydrated stress were taken into account.

The model has been successfully applied to the drilling operations of the horizontal wells in Dagang Oilfield, located in east China. It is confirmed that the optimum densities of the drilling muds predicted with the model are practical, indicated by the quite stable boreholes with very low hole enlargements (less than 10%) in shale formations for the horizontal wells.
Application of Top Drive Drilling to Horizontal Wells
Authors: Murch Colin B.
Published: December 2007

Drilling practices, and the rig equipment required to successfully execute these practices, are critical to the success of horizontal wells. This equipment is often overlooked during well planning. This paper will review the common problem mechanisms associated with drilling horizontal wells and will outline how the use of top drives can help overcome these problems.
Multi-Techhique Comprehensive Interactive Inversion in Sanding Geometry Simulation
Authors: Xu Baoci , Li Chunhua , Dusseault Maurice B.
Published: December 2007

In many oil fields, because of the limitation of geography, humanity conditions, seismic method is impossible to use in oil exploration. In other areas such as where volcanic rocks present then the quality of seismic results will be affected. To solve this problem, a new method called "Optimum Co n-strained Inversion Method (OCIM) "has been developed.

Based on data of constraint area, seismic or drilling, the optimum approach theory can be applied through a optimum fitting function. If the primary parameters of the inversion area are given, rapid iterative inversion can be carried out with OCIM for the detail structure of the inversion area. OCIM can invert the depth of layered structure and opening distribution between layers used in potential field data. According to OCIM, the 3-D tomographic image for density distribution on oil deposit can be obtained and enlarged by filtering of the wavenumber-frequency domain. If the variable values of potential field with time can be monitored, we can obtain the 4-D tomographic structure image or tomographic density distribution image according to OCIM, so that one can use to evaluate structure hazards and avoidance of tectonic hazards during drilling and oil/gas production. This paper also discuss the Accuracy, uniqueness and influence factors of OCIM.
Acid/Rock Interactions During Stimulation of Sour Water Injectors in a Sandstone Reservoir
Authors: Nasr-EI-Din H. A. , Al-Anazi H. A. , Hopkins J. A.
Published: December 2007

A sandstone reservoir in central Saudi Arabia produces sweet, super-light oil. Reservoir pressure support is accomplished by water injection into an aquifer underlying the pay zone. Several water injectors were found to be damaged due to iron sulfide and biomass generated by sulfate reducing bacteria (SRB). The sandstone reservoir is heterogeneous, poorly cemented, and contains up to 11 wt% of clay minerals and up to 0.3 wt% calcite.

An experimental study was conducted to design an effective stimulation treatment to restore the injectivity of the damaged wells, while maintaining the integrity of the formation. Various acids including HCl, acetic acid, regular and retarded mud acids were tested. Stimulation additives including H2S scavenger (aldehydes), iron control agents(EDTA), corrosion (amines) and scale inhibitors (phosphonic acid) were evaluated. Tests included acid-rock interactions under static and dynamic (core flood) conditions. Spent acid was analyzed for key cations using Inductively Coupled Plasma Spectrophotometry (ICP).

Core flood tests indicated that full strength mud acid damaged reservoir cores. Therefore, a half strength regular or retarded HF acid was used. Retarded HF acids which are based on boric acid produced a precipitate (KBF4) and are not recommended for ñeld application. Hydrochloric acid at 7.5 wt% was effective in removing iron sulfide and biomass. However, XRD/XRF analyses indicated that elemental sulfur and CaS04 precipitated inside the core, and were present in the core effluent Addition of EDTA (chelating agent) to the acid substantially increased the concentration of multivalent cations in the core effluent. It also triggered production of fine silica particles and kaolinite, thus the cores were damaged. Hydrogen sulfide scavenger were found not to damage the reservoir cores. Scale inhibitor (phosphonic acid) minimized precipitation of calcium sulfate, however, it caused a significant drop in brine permeability when used at high concentrations (> 0.3 wt%).

Results obtained in this study indicated that a thorough screening of various acids and stimulation additives is needed before stimulating sour wells, otherwise severe damage can occur due to acid reactions with iron sulfide (a corrosion byproduct) and carbonate minerals present in the formation.
Detection Of Formation Damage Associated To Paraffin In Reservoirs Of The Recôncavo Baiano, Brazil
Authors: Khalil C. N. , Rocha N. O. , Silva E. B.
Published: December 2007

This work aims at presenting evidences of paraffination in some reservoirs located in the Recôncavo Baiano, state of Bahia, Brazil, by means of a thermal-chemical method called Nitrogen Generating System or SGN after the original Portuguese expression "Sistema Gerador de Nitrogênio". This method comprises applying the huge amounts of heat and nitrogen gas generated by the reaction between two nitrogen salt-containing aqueous solutions to fluidize the paraffin which becomes then incorporated to the reservoir oil production. In the present work, huge variations were observed for measurements of the melting point, paraffin content, viscosity of the samples, gas chromatography analyses, simulated distillation and wax appearance temperature taken before and after SGN treatment of the reservoirs. It could be seen that the heavy paraffin fraction (C40+) was increased while the light paraffin fraction (C20+ to C40) decreased due to the removal of paraffin deposits from the reservoir next to the perforation.
Evaluation of Paraffin Crystal Modifiers by Dynamic Videomicroscopy
Authors: Magri N. F. , Kalpakci B. , Nuebling L.
Published: December 2007

Conventional techniques for selection of wax inhibitors for crude oils have been limited in that visualizing oil and wax behavior under flowing conditions has not been possible. This paper describes a new technique, videomicroscopy, which allows for visualization of precipitating wax behavior in flowing oil under field conditions. In addition to videomicroscopic data, results of conventional crude oil and model wax systems characterization are given. These conventional techniques include cloud point, pour point, rheology and crystal morphology characterization. Results from videomicroscopy agree with, but go well beyond, what iss learned from conventional analysis. Videomicroscopy shows uninhibited crude to form strong wax aggregates resulting in plug flow, while inhibited oil tends to produce weakly bonded clusters. The technique shows changing behavior of the wax with respect to network formation and deposition as functions of temperature and shear.
Experimental Investigation on the Injectivity of Phenol-Formaldehyde/Polymer Gelants
Authors: Bryant Steven L. , Borghi Gian Paolo , Bartosek Martin , Lockhart Thomas P.
Published: December 2007

Knowing the injectivity of a gelant, i.e. the pressure gradient required to achieve a given flow rate, enables the designer to program the rate/volume schedule of a water shut-off treatment. Bulk gelation times determined from bottle testing have often been used to estimate available pumping time, but such tests do not measure the evolution of gelant rheology as crosslinking proceeds, nor do they measure the tendency of the gelant to undergo filtration within a porous medium. These factors can affect injectivity significantly, resulting in pumping times much less than the bulk gelation time. In this paper we describe techniques for discriminating between vis-cosification and filtration by means of experiments in porous media, making use of multiple pore volume injection, step changes in flow rates, and in-line capillaries. Tests with phenol-formaldehyde crosslinked polymer gelants, which possess a number of characteristics favorable to high temperature applications, show that filtration of pre-gel aggregates in sandpacks and cores can play the dominant role in reducing the mobility of the gelant. The filtration behaviour is not universal, however; one gelant formulation showed no loss of mobility at all by this mechanism. When filtration does occur, it is strongly correlated to the age of the gelant (i.e. time the gelant has spent at temperature) but is relatively insensitive to the permeability of the porous medium or the presence of residual oil. The viscosity of the gelants tested evolves in similar ways in bulk and during flow in porous media.
Analysis of Statistical Methods used in Studying Reservoir Behaviour
Authors: Old R.E. , Saidi A.M. , Zarghamee M.S.
Published: December 2007

The authors have noted that statistical methods in use by some reservoir engineers are biased and can lead to erroneous results. These methods occur particularly in the "fitting" to past history or in the simultaneous solutions of the material balance and water drive equations.

The statistical methods used by various authors are discussed, and a method is suggested to arrive at an umbiased solutions in a particular case. As for the general case, a method is presented that is believed to possess little bias. possess little bias. The bias in other methods is discussed. The mathematics and numerical examples are given showing the weighting factors used in one biased method.

Introduction

Reservoir simulation models and modern high speed digital computers have relieved reservoir engineers of many long tedious hours of punching a desk calculator. This technology has become a mixed blessing, however. There have been evident trends in recent years that has become disturbing -not only in reservoir engineering but in other fields using sophisticated computer simulating programs. One of these trends has been to substitute a programs. One of these trends has been to substitute a mass of computer runs for the usual process of "thinking". The authors have seen several examples where an hour or so of thinking about the mathematical or engineering principles could have obviated hours of program preparation principles could have obviated hours of program preparation and computer time. Sometimes attempts to develop theory by a mass of computer runs have been made; the reversed procedure would be more logical. procedure would be more logical. Another trend that can be seen, particularly in reservoir engineering, is to make these computational systems "empirical tools" - forsaking the excellent theory and logic that was used to develop them. The "fitting" to past history tends to forsake conventional statistical methods to determine basic constants of equations and has instead become a search of wide ranging variables and trends that ends up in a "fit" that may be a complete physical absurdity. This is particularly possible if a biased correlative technique is used.

It has come to the authors attention that some reservoir engineers, are using correlative techniques of minimizing a summation of squared deviations of quantities which may range several hundred folds in magnitude through the field history. These techniques place an uncontrolled bias on one end of the data and virtually ignores the other end of the data. These techniques of masking the effects of one end of the data give a false sense of security amidst the errors of the basic data.
In-Situ Remediation of Oil-Contaminated Soils with Surfactants: Laboratory and Pilot Studies
Authors: Baviere M. , Bocard C. , Ducreux J. , Monin N. , Muntzer P. , Razakarisoa O.
Published: December 2007

M. Baviere, SPE member, C. Bocard, J. Ducreux, N. Monin, Institut Francais du Petrole, and P. Muntzer and O. Razakarisoa, Institut Franco-Allemand de Recherche sur l'Environnement (IMF-CNRS) Copyright 1997, Society of Petroleum Engineers, Inc.

A surfactant-flooding technique is described for the remediation of soils contaminated by semivolatile and nonvolatile petroleum products, such as crudes and diesel oils. It consists of injecting a surfactant slug into contaminated areas to mobilize oil trapped in both vadose (unsaturated) and capillary-fringe zones, and of depleting the groundwater level to collect this oil.

To deal with contamination by diesel oil, a procedure to select a surfactant formulation was applied, based on (1) the phase behavior of the water-oil-surfactant system, (2) an appraisal of surfactant-soil interactions, namely ion exchange with clays and surfactant adsorption, and (3) the measurement of the surfactant efficiency for extracting the contaminant from 1D and 2D sandpacks. With a mixture of anionic and nonionic surfactants more than 90% of the residual oil was recovered.

The process was implemented in a large-scale experimental site of 900 m3, packed with slightly clayey sand and locally contaminated by a spill of 476 L of diesel oil. Two successive surfactant injections were performed in order to treat: first, the vertical oil-migration zone; secondly, the horizontal oil-extension zone in the capillary fringe. Based on soil-core sampling after the surfactant flood, the high displacement efficiency was confirmed: about 80% after the first injection. However, it appeared that the mobilized oil was not entirely recovered at the pumping well: about 50% of the residual oil, probably due to insufficient hydraulic confinement. The same observations were made after the second injection. The removal of diesel oil and surfactants from the effluents was performed on-site, before sewage disposal, by centrifuging, precipitation and finally by biodegradation.

Introduction

The remediation of soils and aquifers contaminated by petroleum products is now proving increasingly essential in the protection of human health. To palliate the poor efficiency of conventional pump-and-treat processes, due in particular to capillary trapping and the low water solubility of contaminants, alternative in-situ restoration strategies have been developed, such as venting, biodegradation, and surfactant flooding. The latter is particularly promising when semivolatile and nonvolatile contaminants are involved.

The use of surfactants is investigated here in the framework of a modular process: the DHBP (Drainage HydroPneumatique Bioactif). It consists of implementing one stage of surfactant flooding and one stage of surfactant-enhanced biodegradation. P. 481
Information Obtained by Correlating Probable Values of the Geological Reserves and of the Influx Constants
Authors: Baldini G.
Published: December 2007

The correlations between probable values of the reserves, the invasion constant and the dimensionless time constant are obtained for oil or gas reservoirs with infinite or finite, radial or linear aquifer, by superposing the effects due to a succession of uniform declines of the pressure at the initial gas-water (oil-water) contact.

The behavior of correlations deduced for the considered reservoir-aquifer system at each material balance calculation, is successively analyses and found as giving useful information. In fact, when represented in linear diagrams, they can be the basis to evaluate with a good approximation the geological reserves, the properties of the water influx and, also, to find the pressure values in the past production history which have the worse influence on the results of the material balance.

This is useful in the initial phase of reservoirs exploitation giving information to predict earlier their future behavior, when the instrumentation and evaluation errors in the reservoir pressure can be of the same order of the pressure drop in the corresponding time intervals.

The correlations can also provide a method for the simultaneous determination of the unknown parameters of the aquifer-reservoir systems which can be used in any case in combination with the usually methods, to give more complete results.

Introduction

We will assume, as usually: an homogeneous and istropic aquifer with constant thickness (linear or radial, finite or infinite); a deplacement front undeformed by fluids different densities; the absence of collateral phenomena as the compaction of the surrounding shales or the oversaturation of the oil; uniform conditions in all zones of the reservoir; the pressure at the initial hydrocarbons-water boundary equal to the average pressure of the reservoir until the last calculating time; always a sufficient number of wells.

Moreover, we prefer to express the water influx by superposing the effects of the pressure variations at the reservoir-aquifer boundary as due to successive linear declines in every production interval. We do this with the formulation 1).
Influence of the Viscoelastic Properties of the Overlying Rocks on the Behaviour of the Deep Aquifers
Authors: Brighenti G.
Published: December 2007

The pressure variations in the aquifers, consequent on the production, of an oil or gas field or on gas injection for the production, of an oil or gas field or on gas injection for the underground storage, causes variations of the tensions being both in the permeable medium and in the overlying strata.

This fact, as we know from the literature about this argument, causes both permeability and porosity variations of the medium, influencing therefore the water influx, and remarcable deformations in the enclosing rocks which might cause subsidence phenomena too.

In the note, we are going to present, the phenomenon is studied in all these aspects through the Finite Elements Method, taking in consideration the results obtained in the Mining Science Institute of the Bologna University.

The behaviour of the water-bearing stratum and of the overlying rocks was namely studied unitedly. After dividing properly, the medium into finite elements, both the pore properly, the medium into finite elements, both the pore pressure distribution and the consequent tension variations pressure distribution and the consequent tension variations as well as the deformations through the time, were studied at the same time through an iterative process; the viscoelastic medium was represented according to the Kelvin-Voigt generalized model.

Introduction

1. The developing of the reservoir engineering compelled the researchers to the requirement to always know more thoroughly the characteristics of fluids and reservoir rocks.

As far as reservoir rocks are concerned, it has been thought to be necessary, already since many years, to take into account their compressibility and the variations of their physical characteristics when reservoir pressure changes, especially in the case of liquid one phase expansion; on this subject several studies have been performed. From these researches the importance aroused to wholy study the phenomenon, by taking into account not only reservoir rocks or the aquifer, but also all surrounding rocks. As regards the above said, the important conclusions reached by Geertsma, Van der Knaap and Van Vlis, and Evangelisti and Poggi are mainly aimed to detect the subsidence phenomena.

Under this note, the attention is particularly called upon the influence of a variation of the reservoir pressure both on the whole medium strain and on the fluid influx in case of overlying rocks with a viscoelastic behaviour. To this purpose, we took as a basis the results obtained from the research in course at the Instituto di Scienze Minerariein Bologna, performed by means of funds from Consiglio Nazionale delle Ricerche.
Chemical Study of Organic-HF Blends Leads to Improved Fluids
Authors: Shuchart Chris E.
Published: December 2007

Organic-HF blends have successfully stimulated sandstone formations with corrosion concerns, HCl-sensitive mineralogy, and/or crude oil incompatibilities, three conditions in which the use of typical HCl-based fluids can result in severe damage. Despite the success of such blends, very little work has been published on the reactivity of organic-HF fluids with aluminosilicates. Recent work on the chemistry of HF acidizing focused on HCl-HF systems.1 This paper discusses the chemistry of organic-HF systems as determined by laboratory reactivity tests, 19F nuclear magnetic resonance (NMR) studies, and organic-HF flowback analyses.

Laboratory reactivity testing revealed severe precipitation problems associated with the currently used acetic-HF and formic-HF systems. Flowback analyses after organic-HF field treatments fully supported the laboratory results. A 19F NMR spectroscopic study of the fluoride distribution throughout the primary, secondary, and tertiary reactions helped explain the precipitation and when it might occur. From this work, new organic-HF systems were developed that prevent precipitation while maintaining all the advantages associated with the acetic-HF and formic-HF fluids. The retarded nature of these systems is discussed in this paper.
Permeability Impairment due to Asphaltenes During Gas Miscible Flooding and its Mitigation
Authors: Turta Alex T. , Najman Joseph , Singhal Ashok K. , Leggitt Shelley , Fisher Douglas
Published: December 2007

Introduction

During miscible flooding of oil reservoirs by light hydrocarbon gases, deposition of asphaltenes inside reservoirs, and injection and production wells, can cause severe problems thereby adversely affecting the economics of oil recovery. In spite of this, very limited information regarding the asphaltene adsorption/deposition within porous media during gas miscible flooding, is available.

In the present work, the flow of oil-solvent mixtures through porous media during a gas miscible flood was mechanistically studied in the laboratory under simulated reservoir conditions. The tests mimic the phenomena occurring within a small pore volume encroached by increasing amounts of solvent, in the course of a miscible flood.

Experimental

Two Canadian crude oils, known to be prone to asphaltene deposition in the field, were selected for this study: one from the Pembina Nisku pool in west-central Alberta and the other from Rainbow Keg River field in north-western Alberta.

Both these oils have an asphaltene content of about 2%.

For studying asphaltene related effects inside porous media during miscible flooding, a high pressure coreflood equipment was constructed (Figure 1). Berea cores were used as porous media during this investigation. The lengths of the cores were over 20 cm and the diameters, 1.9 cm. The porosity was 16-17%. The effective permeability to oil was in the range of 36 to 116 mD; these values were measured at a residual water saturation of 27–28% and were used as reference values for the subsequent flow of oil-solvent mixtures. Reservoir brine was used to initially saturate the core; a subsequent oil flood reduced the brine saturation to the residual brine saturation.

Results

Variations in effective permeability ratio (Kef/Kefo) upon flow of Rainbow Keg River oil-propane mixture are presented in Figure 2; here Kefo is the original value of effective permeability (for oil), while Kef is the current value for a given propane concentration in the mixture. All the concentrations are expressed in vol. %. The reduction of Kef begins as soon as propane is injected, that is, at a concentration of 15% propane, and it continues until propane concentration, reaches 100%. As a matter of fact, when injecting pure propane, the Kef is reduced to almost zero, implying a total blockage of the porous medium. There are two rates of permeability decrease with increasing propane concentrations, corresponding to two distinct ranges of propane concentrations. The first range is up to 51% for which the decrease is very steep. For propane concentration higher than 51%, the decrease is less severe. At the end of the first range, the Kef had decreased to 26% of its original value.

P. 703^
The Critical Water-free Production Rates of Interfering Wells
Authors: Lehner F.
Published: December 2007

The critical rate is defined is the steady or semi-steady production rate of oil or gas under a drawdown just small enough to prevent water production from an existing layer of bottom water. production from an existing layer of bottom water. Critical rates are determined theoretically for fully perforated wells, assuming a horizontal cap-rock perforated wells, assuming a horizontal cap-rock boundary and allowing the permeability to vary with depth. A generalised 'Girinskii Potential' is defined and used to formulate the three-dimensional free-surface flow of a real gas as a problem in plane flow. A formal analogy with plane incompressible flow is thereby established. As an example, Muskat's results for the flow capacities of small groups of interfering wells are reinterpreted in terms of critical oil or gas production rates.

Introduction

The occurrence of bottom water in oil or gas reservoirs imposes restrictions on water-free withdrawal rates, since a well will cut water above a certain critical rate. This critical rate is associated with the well-known phenomenon of upconing bottom water. The phenomenon depends essentially on the perforation and intake provisions (position of the tubing-intake level) at the well. To ensure a finite critical rate, these provisions must be such as to allow i water cone to rise a finite distance above an initially flat oil/water contact without immediately reaching the perforated interval or the tubing-intake level inside the well. A steady state can then exist in which the water remains stagnant up to line critical rate and, due to its greater density, hydrostatically balances the pressure gradient in the foil or gas which passes over it towards the well. passes over it towards the well. The assumption of steady-state conditions and of fully segregated fluids separated by a macroscopically sharp interface form the starting point for the majority of investigations concerned with the determination of critical rates. Among these, a further distinction can be drawn between studies dealing with partially penetrating (or partially perforated) wells and those dealing with fully perforated) wells and those dealing with fully penetrating and fully perforated wells, i.e. wells penetrating and fully perforated wells, i.e. wells perforated over the total pay thickness. perforated over the total pay thickness. This article deals with the case of fully perforated wells. perforated wells. The critical production rate of a fully perforated well sited in the centre of a horizontal perforated well sited in the centre of a horizontal circular reservoir, assuming steady incompressible flow, can be determined with the help of Dupuit's famous well-discharge formula upon giving the proper interpretation to the quantities involved. proper interpretation to the quantities involved.
A Patch-Type Adaptive Local Grid Refinement Technique and Its Application to Horizontal Wells
Authors: Vikas Shree , Ertekin Turgay
Published: December 2007

A three-dimensional, three-phase black oil simulator is developed which incorporates both static and dynamic patch-type local grid refinement procedures; and is capable of handling both horizontal and vertical wells. In static local grid refinement the refined grids are embedded within the coarse grids during the entire length of simulation. This refinement scheme has been used around the wellbores where large pressure and saturation changes are anticipated. The dynamic local grid refinement algorithms identify various sections of the reservoir undergoing large pressure and/or saturation changes at each timestep. A pre-determined uniform refinement is applied to these patches; and local grid simulation is performed. The local grids and the base (coarse) grid interact with each other through a specially developed data transfer method; in which the local gridblock pressures are arithmetically averaged to get updated coarse gridblock pressure, and capillary pressure is used to back calculate phase saturations. Once all the patches are solved then the corresponding coarse gridblock pressure, saturation and flowrate entries are updated from the entries of the local grids.

The performance of the developed model is examined through several different scenarios. These cases include sealed reservoir, bottom water drive, and edge water drive utilizing horizontal wells. The proposed refinement algorithms provide good estimates of bottom-hole flowing pressures, WOR and GOR values and flowrates for all the configurations. The run-time for the dynamic grid runs is about 100–200 folds less than that of the fine-grid model, and is comparable to the run-time of conventionally refined grid model. Local grid simulation in various patches of the reservoir do not share or transfer data among each other at a particular timestep. Hence, this technique can be easily implemented on machines having parallel processors. Such applications would drastically reduce run-time.
Developing a 10 billion barrel reservoir with modern techniques
Authors: Joiner D.S. , Myers C.E.
Published: December 2007

A high volume water injection pressure maintenance program was initiated in the Defa Field of the Libyan Arab Republic soon after production began, to maximize oil recovery. As development of this large reservoir proceeds, the injection system can be expanded to a capacity in excess of 400,000 BWPD to support oil production rates of about 350,000 BOPD.

Development of Defa contrasts with that of older large fields due to the abundant use and application of modern tools and technology. Computer model studies predicted the need for pressure maintenance and were used to plan the pressure maintenance and were used to plan the large bottom-water injection system which was designed, constructed and put into operation in the Libyan desert only 20 months after the Field was put on production. Thirty-four months after the Field went on production, 163,000,000 barrels of oil had been produced from, and 80,000,000 barrels of water injected into, the Defa reservoir. This water injection program is expected to increase oil recovery at program is expected to increase oil recovery at least 300 percent from about 1 billion barrels to over 3 billion barrels.

Introduction

The Defa field in the Libyan Arab Republic contains oil-in-place of about 10 billion barrels; however, computer model studies predicted the need for pressure maintenance predicted the need for pressure maintenance early in the producing life of the field. The studies showed that the under-saturated crude would quickly drop below the bubble point and institute an inefficient, solution point and institute an inefficient, solution gas expansion drive without some type of pressure maintenance program. A large-scale pressure maintenance program. A large-scale water injection system, designed with the help of the computer model studies, is predicted to increase oil recovery 300 percent from about 1 billion barrels to over 3 billion barrels.

This paper reviews the development of the field and studies leading up to the initiation of water injection, with particular emphasis on the use of modern tools and technology. Such advances in technology reduced the time spans required for major development decisions. This 10 billion barrel field was put on production 500 miles from Tripoli in the Libyan desert only 23 months after development commenced. Twenty months later, a 240,000 BWPD water injection system was in operation.
Two-Phase Flow through Wellhead Chokes
Authors: Fortunati F.
Published: December 2007

It is possible to find in the literature, some papers concerning the two phase flow through the wellhead chokes, but nearly all these contributions concern only the critical flow.

The critical flow, when only the gas is concerned, happens around a choke downstream - upstream pressure ratio of about 0,5, but this condition is no more valid as the flow is two phase (gas and liquid). The velocity of a two phase flow, both critical and subcritical, is greatly depending from the gas concentration in respect to the mixture, and the downstream - upstream pressure ratio can be also lower than 0.225. pressure ratio can be also lower than 0.225.The practical cases, as experienced during several years, are nearly all in the subcritical flow field, and in the present paper, a simple formula is given for calculating the rates through the wellhead chokes, covering both the critical and subcritical flow fields.

The equation below reported, can be easily also developed through a computer program.

In the text, the number between square brackets, refer to the literature, and the numbers between round brackets, refer to the equations.

This paper is mainly intended for practical purposes, some unavoidable calculation developments were confined in the Appendixes.

A full relief was given to the illustrative numerical examples and through all the paper the metric system of units is used.

Introduction

Since recently two phase flow is receiving more and more attention by the researchers working in the oil industry. It can be said that no one month passes without appearing in the literature, scattered over the world, a contribution concerning this item. The impulse to these researches came from the observation that the pressure drop through a pipe, when flowing a gas/oil mixture, can be also ten times more than that due to a single phase flow.
Calculating Accurate Gas-Lift Flow Rate Incorporating Temperature Effects
Authors: Bertovic D. , Doty D. , Blais R. , Schmidt Z.
Published: December 2007

Gas lift is a common, widely used method of oil production. Efficient design requires knowing the performance of each component of the system. Theoretical analysis supported by experiments is needed to determine a practical model for gas-lift valve performance.

Two sets of experiments are described:to obtain standard flow performance data, andto investigate the influence of temperature distributions on the bellows temperature of a nitrogen-charged gas-lift valve.

The new, empirically based calculation procedure presented is superior to existing procedures by:being independent of whether the constant injection pressure or constant production pressure method is used,reducing the number of empirical model parameters to five,addressing all three gas-lift valve flow regimes: (orifice, transition and throttling), andpredicting gas-lift valve performance more accurately than existing models.

Introduction

For gas-lift operations, reliability and efficiency depend on accurately predicting the performance of the gas-lift valve. Valve performance is defined as the standard volumetric flow rate of gas through the valve as a function of the injection pressure and production pressure for a given port size, and bellows set pressure. Temperature sensitivity, corrosion and erosion resistance, and vibration suppression also affect valve performance.

The degree of temperature sensitivity has been ignored in earlier models under the assumption that the bellows temperature equals reservoir temperature. The large drop in temperature on the production end of the valve where expanding gas exits is familiar to anyone who tests valves. This indicates the lack of a single well defined equilibrium temperature in the vicinity of the valve. An experiment is reported here that assesses the sensitivity of valve performance to this temperature distribution.

Furthermore, experimental studies have identified three flow regimes in the valve with transition flow separating orifice flow from throttling flow. Existing models predict performance for orifice and throttling flow, but not for transition. They also apply subjective supplementary criteria to determine the flow regime and then select a distinct model for that regime. The new model described here applies to all three regimes and objectively predicts which flow regime applies under the design conditions. Finally, this procedure illustrates the sensitivity of the gas-lift valve to temperature.

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Performance Of Oil Muds At High Temperatures
Authors: Methven N.E. , Baumann R.
Published: December 2007

This paper presents data on the performance of oil muds at high temperatures and high pressures. Included are data and discussions regarding static densities, circulating densities, thermal stability and stability in corrosive environments.

The information on static and circulating densities combines PVT data, recently published methods of computing downhole transient and pseudo-steady state temperature data as functions pseudo-steady state temperature data as functions of circulating rates and geothermal gradients, and recently available rheological properties of oil muds at high temperatures and pressures.

Thermal stability of various oil muds are discussed on the basis of theoretical physiochemical behavior of the constituents physiochemical behavior of the constituents as well as on the basis of laboratory aging and rheology data. In addition, data on oil base mud in the presence of hydrogen sulfide and carbon dioxide are presented.

The data and analyses indicate that the two basic oil mud types, oil base and invert emulsion, have several distinct differences in performance characteristics at high temperature. It appears that the invert emulsion muds have temperature limits (at least economic) because of thermal degradation of their synthetic organophilic colloids and organic surfactants. Critical degradation may occur in a matter of hours at 500 degrees F.

Oil base muds that use certain asphalts for the colloidal material have a higher temperature stability. This is because the asphalt does not degrade, at least up to 540 degrees F. and, because the asphalt is a hydrocarbon, does not need synthetic oil wetting and is in itself an emulsifier, and oil wetting agent and surfactant.
ESP Motor Voltage Adjustment for Maximum Profits
Authors: Lea James F. , Liu Joe
Published: December 2007

Oil production with lift requires a lot of energy. It is not uncommon for a major oil company to have energy costs for total lift approaching $100,000,000/year. Because of this, any easily practice that can save even a fraction of these costs can be advantageous. This paper addresses what is the best voltage for ESP motors (systems) that are running at load conditions other than 100%. Reference 1 shows advantages to lowering the voltage on and ESP installation when the motor is less than 100% loaded. One ESP manufacturer has literature suggesting that if an ESP motor is 20% under-loaded, then the voltage to the motor should be lowered by 10%. Also it is known that increasing the voltage over name plate will speed up the unit and you can get more production. Some total system examples are presented to illustrate these effects for some particular equipment.

This paper should apply to any operator that finds a new or old installation where the load is not near 100% on the motor and consideration is made to whether or not to change the applied voltage.

There are many of recommendations from the ESP manufacturers to the end users about how to maximize system efficiency. Sometime these instructions are confusing or difficult to follow by the end users, especially when the motor is operating under "off full load" situation.
Horizontal Well Completion With Stinger for Reducing Water Coning Problems
Authors: Permadi P. , Wibowo W. , Alamsyah Y. , Pratomo S. W.
Published: December 2007

A laboratory experiment has been conducted to study the behavior of water coning under a horizontal wellbore having a stinger inserted. A large Hele-Shaw cell was used to perform the experiment. The length of the stinger employed, oil viscosity, and initial thickness of oil column were varied to investigate their effects on the optimal length of the stinger.

Results obtained show that systems without stinger yield better early recovery performance. Installing a stinger flattens the cone of water and reduces the rate of increase in water cut, leading to an improved recovery significantly. It is found here that the optimal stinger length is about 0.3 of the length of the horizontal wellbore section, regardless of the initial thickness of oil column and water/oil mobility ratio.