bluuebunny/crossref_metadata_2025 huggingface dataset:
Completing Oilfield Projects in Arctic Russia: "Both Points of View"
Authors: Roobaert N. C. , Vladimirov Anatoly
Published: December 2007

The way that oil fields are developed in Russia and how western companies work with their Russian partners, Russian Institutes, and Russian contractors have been burning questions since Russia has been made open to Western participation. As Russian and Western companies continue to partner more is learned each day about how to work together. Naturally, some experiences are good and some are not so good. Each side has his own story as to why things went well or not so well. This paper presents both points of view and discusses a way of working together. The two views are presented by the Chief Engineer of a Russian Institute and by the President of an American Engineering Firm. These are individuals who have worked together over the past two years on projects in the Timan Pechora Basin. Although, these are thoughts and feelings of two people who have actual experience working together, by no means is this paper represented to be a general statement of every situation. No doubt, others have different experiences, thoughts and feelings.

The future of working relationships between Russian and Western companies is bright, but it does take work, nurturing, patience and an understanding of each other. The purpose of this paper is to add to that understanding. Both points of view are presented. The capabilities of, type of work best performed by, and advantages of working with a Russian Institute are discussed. It also presents the equipment and services that can best be supplied and performed by Russian companies now and in the future. Finally, it presents a way of best working together as partners.

This approach of presenting both points of view is unique as far as we know. Of major importance is the genuine response from the Russian point of view. These responses have not been altered. This will be apparent as one reads the paper, but it also represents some of the difficulties that must be worked through in building a relationship. In very few cases liberties have been taken in translation to clarify the meaning of comments by Mr. Vladimirov. These responses are important because not only is an assessment made of the subject under consideration by someone who has first hand knowledge, but we must also read carefully the comments of Mr. Vladimirov, particularly his understanding of the subject, the honesty of his answers and his ability to answer in such a way that it is understood by the readers of this paper.
Successful Gas Shutoff with Polymer Gel Using Temperature Modeling and Selective Placement in the Prudhoe Bay Field
Authors: Sanders G. S. , Chambers M. J. , Lane R. H.
Published: December 2007

A combination of known crosslinked gel chemistry with careful problem diagnosis, wellbore and formation temperature modeling, and zone isolation techniques yields a high success rate for shutting off unwanted gas influx into production wells in the Prudhoe Bay Field of Alaska. The paper includes candidate selection criteria, methodology of temperature simulation, job design, field operations case histories, and pre- and post-job production data for evaluation of success. This approach has led to a 60% technical success rate, primarily on wells that had cement squeeze failures. Job costs are about 75% those of comparable cement squeezes.
A Gelation System for Conformance Technology
Authors: Dalrymple Dwyann , Tarkington John T. , Hallock James
Published: December 2007

This paper presents a technique to reduce or plug permeability to water in primary hydrocarbon production wells and secondary injection hydrocarbon wells without causing damage to the subsurface environment. The principle of the operation is to pump a water-thin monomer solution in a single stage into the formation. The monomer then forms a polymer through a process activated by well temperature. Relative solubility of the resulting gel is directly controlled by the concentration of monomer placed in the formation. The polymerized material (gel) plugs pore spaces and channels, thus limiting undesired fluid flow.

The ecologically friendly system (EFS) avoids use of metal crosslinkers and allows for extended and reproducible gel times; it is nontoxic and acid-resistant.

Treatment techniques described in this paper may be applied to correct numerous conformance problems, including those listed below: coning in production wellshigh-permeability streaksinterwell channelinginjection out of zone
Field Trials of Multiphase Metering Systems at Prudhoe Bay, Alaska
Authors: Priddy W. J.
Published: December 2007

A prototype Cl 1500 positive displacement multiphase metering system has been tested at Prudhoe Bay, Alaska. The trial, conducted during 1992-93, extends previous test experience, covering pressures of 200 to 2300 psig and gas void fractions of 62% to 95% These represent the most difficult multiphase flow conditions from the metering standpoint but are widely applicable. Reproducible phase flow rate measurements to within ±5% relative of the reference single phase measurements were achieved by the multiphase meter on the basis of a simple factory calibration using tap water. In combination with previous testing, the trial has given confidence in reliability and demonstrated resilience of the calibration. Water cut measurements required by the system were attempted using a capacitive phase fraction cell. This indicated that water cut can be measured in high gas fraction streams using a conditioned sampling signal analysis technique.
Status of Multiphase Flow Measurement Research
Authors: Williams Jane
Published: December 2007

Research in multiphase measurement has been accelerating over the last few years. The reasons for this interest level are primarily economic in nature. It has been estimated that more than 50% of the world’s proven reserves of oil and gas are located in water depths greater than 1000 feet.1 These water depths demand innovative and economical developments, in order for projects to be viable. Some of the more promising methods for economical production in deep water include multiphase measurement, especially in conjunction with multiphase pumping. Subsea production, measurement and transportation to shore or to an existing platform may allow more efficient and less costly processing, thus minimizing platform costs. On some projects, it may be possible to eliminate separation equipment and test lines which will result in tremendous economic savings. This paper will explore the advantages of multiphase measurement, methods utilized for multiphase measurement to date, research to date, and projected future research.
Hydrocarbon Blowdown from Vessels and Pipelines
Authors: Norris III H. L.
Published: December 2007

In SPE 26565 presented at the 68th Annual Technical Conference in October, 1993, analysis and experimental results were presented for the blowdown of pipelines and vessels using air, carbon dioxide, and carbonated water. Since then further experiments have been carried out using several hydrocarbon gases including both methane and heavier mixes.

The pronounced difference in the blowdown behavior between pipelines and vessels noted in the earlier non-hydrocarbon experiments was confirmed for the hydrocarbon gases tested. In addition, for vessel blowdowns, the presence of condensed hydrocarbon liquid was shown to increase the mass efflux rate over an otherwise equivalent single-phase methane blowdown. By contrast, pipeline efflux rates were found to be virtually insensitive to gas composition over the range of hydrocarbon gases tested.

These experimental results were compared to the analytical methods described in the earlier paper, and initial efflux rates were found to agree with measured values within about 20%. In addition, the measured efflux rates can serve as test cases for comparison to other analytical methods.
Space Age Material Technology Extends Beam Lift Capacity
Authors: Lea J. F. , Hensley H. N. , Christian Jimmy , Hettinger Douglas , Meisner William , Anderson Howard
Published: December 2007

This paper describes the development and use of a Continuous Carbon Fiber Sucker Rod which is in the configuration of a reelable "tape" or "ribbon" with current dimensions of 1.45 in. x 0.212 in. It can be wound on a 10 ft diameter reel, 6 in. wide. It is designed to be run with some steel rods on the bottom similar to fiberglass rods. Its performance can be designed and analyzed using wave equation type mathematical models. This particular light weight material, for use as sucker rod replacement has been successfully tested in the lab and field over the past ten years. It was conceived as a method requiring no couplings, using a corrosion resistant, light weight material.
Performance of Hydraulic Fractures in High Permeability Formations
Authors: Hunt James L. , Chen Chih-Cheng , Soliman M. Y.
Published: December 2007

Fracpack is the hydraulic fracturing of high permeability (generally > 10 md) formations to increase well productivity and control sand production. Fracturing aspects of the fracpack process have been discussed recently in the literature.1,2 However, the reservoir engineering aspects and justification for fracpack have not been extensively studied. The reservoir engineering aspects of fracturing low permeability formations have been widely documented throughout the petroleum literature.3 However, fracturing high permeability formations differs from fracturing low permeability formations. To ensure the success of a fracpack treatment, the candidate well needs to be chosen carefully with consideration given to rock mechanics, reservoir engineering and operational aspects of the fracpack process.

Generally, hydraulic fracturing is usually thought of as a technique to increase productivity or establish production in low permeability reservoirs. However, benefits can be realized by fracturing highly permeable formations that have formation damage and/or sand production tendencies. A well that has reduced permeability several feet or tens of feet away from the wellbore can be made more productive by fracturing through this damaged zone to contact undamaged reservoir. Reservoir fluids are thus provided an unrestricted pathway from undamaged reservoir to the wellbore. The conductivity within the fracture can be maximized so that pressure drop along the fracture itself can be held to a minimum. In the case of a well with sand production tendencies, a hydraulic fracture decreases the pressure drop necessary to produce the well at a given rate and changes the flow regime around the well such that sand production is minimized or eliminated. Thus the well may be produced at a rate higher than the unfractured critical sand producing rate.

Operationally, fracturing high permeability formations is different from fracturing low permeability formations due to the expected high leak-off rate, which influences fracturing pressure as a function of time. In addition, because of the desired high fracture conductivity, the concept of tip screen-out is applied. In tip screen-out, the fracture is designed in such a way that by the time the fracture reaches the desired length, the leading pad volume has leaked off into the formation. After the pad volume has leaked off, the presence of the proppant-laden-fluid at the leading edge of the fracture initiates the screen-out process. Continued injection of the proppant laden fluid causes the fracture to widen or balloon, reaching a greater than average width and high proppant concentration (a packed fracture). During the packing period, the fracturing pressure is expected to sharply increase.
Water/Oil Separation Characteristics of Daqing Oilfield Polymer Flooding Production Fluid
Authors: Jiachao Feng , Jiansen Zhao , Shaobing Chan , Chengjie Qu
Published: December 2007

As an effective EOR method, polymer flooding has been recognized all over the world for its excellent flooding effect under certain conditions, large scope of recovery percentage improvement and good economic benefit. However, because of the large quantity of polymer contained In the produced fluid from the polymer flooding areas, oil-water separation Is becoming more and more difficult. This article, based on the actural conditions of the polymer flooding pilots, and the data from the pilots, discuss the gravity settling separation characteristics and the characteristics of electro-chemical dehydration under the condition of produced fluid with various concentration of polymer, analyzing the effect of water phase viscosity increase of polymer onto the oil-water separation rate, oil-water emulslflcation intensity, water-cut varatlon of the produced fluid and the electrochemical dehydration. Some research directions and the problems which should be paid attention to are also put forward.
An Innovative Way to Produce and Transport Heavy Oil Through Dispersion in Water: Laboratory Study and Field Test Results
Authors: Bertero Luigi , DiLullo Alberto , Lentini Amelia , Terzi Luigi
Published: December 2007

A patented innovative system to produce and transport heavy and very viscous oils was developed in the laboratory and tested in the field. Results show a remarkable improvement comparing this system to the traditional ones based on the injection of a hydrocarbon diluent or of a surfactant solution to produce an oil-in-water emulsion.

The system is based on the injection of a water stream, to which a dispersing agent has been added, into the well without any modification of the existing completion. Field tests show that, as soon as the water solution comes into contact with the crude, an oil in water dispersion (70/30 oil-water ratio) is created with a viscosity 30-50 times lower than the viscosity of the diluted crude. A fourfold increase in oil production was also achieved compared to normal production with the injection of diluent.

The produced dispersion was pumped to the oil collection centre, 1 Km from the well, showing a decrease of friction losses along the pipe of six times that of the diluted crude. Temperature variation down to 5 °C does not affect viscosity while the diluted crude viscosity shows an increase by a factor of ten compared to the viscosity at normal ambient temperature (20-25 °C).

Separation of the dispersion depends on the dispersing agent concentration and on the degree of mixing of the dispersion itself.

Gravity separation produces a crude oil with a 6-8% water-cut. This was achieved without the addition of any demulsifier and using the same settling time normally used in the field facilities to separate the water-diluted crude mixtures. The residual water can then be separated with a traditional electrostatic separator.
Sensitivity Study of Foam Diversion Processes for Matrix Acidization
Authors: Kibodeaux K. R. , Zeilinger S. C. , Rossen W. R.
Published: December 2007

Factors key to the success of foam diversion processes for matrix acidization were measured in Berea cores. Foam mobility was low in high-permeability (847-md) Berea and higher in low-permeability (92 md) Berea, suggesting effective foam diversion. Injection of surfactant solution, emulating foam-compatible acid injected following foam, trapped some of the foam in place, but imputed diversion of acid was not as complete as diversion of foam itself. After a period of injection of liquid, more gas was displaced, starting from the core inlet, and mobility rose further. Using these coreflood results, fractional-flow methods predict effective acid diversion between layers differing in permeability in field application. A sensitivity study indicates that the size of the preflush and the propagation rates of foam within rock are secondary factors in the success of foam diversion in the field. Foam strength and especially gas trapping following foam injection are the keys to successful application. In a process in which gas trapping following foam injection is ineffective, or is less effective in high-permeability layers, a continuous-injection foamed-acid process would outperform a process of alternating slugs of foam and acid. Further data, especially in field cores, are needed to confirm these conclusions.
How Effective is In-Situ Crosslinked Gelled Acid in Remedial Fracture-Acidizing Treatments?
Authors: Cramer D. D.
Published: December 2007

A study of remedial fracture-acidizing treatments in the Little Knife field indicates that treatments using in situ crosslinked gelled acid und er-performed treatments using a standard copolymer gelled acid system. This finding contradicts previous studies that claimed in situ crosslinked gelled acid treatments yielded a five-fold productivity improvement over ‘conventional" acid treatments in the same field.
Measuring Diffusion Coefficients in Acid Fracturing Fluids and Their Application to Gelled and Emulsified Acids
Authors: de Rozieres John , Chang F. F. , Sullivan R. B.
Published: December 2007

To predict the length obtained from an acid fracturing treatment, acid fracturing models require that diffusion coefficients values be included in the equations describing the transport of the acid to the surface of the rock.

Numerous data have already been published for hydrochloric acid, but very often these data were not generated under conditions representative of the field. For instance, values for diffusion coefficients in straight acid are only available at low normality. In reality, acid fracturing models should use diffusion values for spent acid at a higher concentration.

Gelled and emulsified acids are also widely used in acid fracturing treatments leading to increased fracture length and conductivity due to decreased leakoff and a "retardation effect." Unfortunately, very few diffusion data are available for these fluids.

The diffusion coefficient of an ion in a fluid is a physical property which can be obtained from direct measurement. This paper presents measured diffusion coefficients for straight and gelled acids using both a diaphragm diffusion cell and a rotating disk apparatus. In addition, diffusion coefficients for emulsified acids, as obtained from the rotating disk apparatus, are also presented.
Water-Coning in a Fractured Reservoir
Authors: Van Golf-Racht T. D. , Sonier Fernand
Published: December 2007

The Coning problem in a "conventional reservoir" (porous media) has always been examined in the light of "preventing the water-cut" in oil production wells which partially penetrate an oil layer underlain by water. For almost six decades all of the papers concerning the water-coning problem have limited their investigation to the evaluation of the "maximum" water-free or gas-free production rate (called the "critical oil rate") versus the oil pay magnitude and well penetration depth into the oil interval. The objective of this paper is the extend the investigation to the coning criteria in a "fractured reservoir" by including the production of oil and water and not only preventing the production of water.

Such a changement in the Muskat criteria required an examination of the fluid flow toward the well in the fracture network and thus the coning development and behaviour associated with the coning water-cut and total fluid production rates. The relationship of "coning water cut" vs. "production rate" in time in a fractured reservoir was examined for the first time out of the classic design approach of the coning production.

Among the problems examined are: 1) the role of "well completion" and its design in relation to the production of oil and water from a fractured reservoir, 2) the role of the "reverse coning" in estimating the maximum coning water-cut, 3) reservoir "internal architecture" role associated with the matrix "blocks size" influence on coning water-cut behaviour, 4) the role of horizontal and vertical fracture density, which is equivalent to a certain degree of anisotropy. The results of the study have demonstrated the gain of some important ideas in the water coning area and the combined effect of various reservoir characteristics for an optimized design of a well producing from a fractured reservoir.
Understanding Cavity Well Performance
Authors: Young G. B. C. , Kelso B. S. , Paul G. W.
Published: December 2007

Open-hole cavity completions provide significant improvement in gas production from the Fruitland coal play in the northern San Juan basin. Where reservoir properties are favorable for cavitation, such as in the basin’s "fairway" area, gas production rates from cavitated wells generally exceed production from wells completed using hydraulic stimulation techniques, often by a factor of 3 to 10 times. Analysis of regional geologic trends and a simulation-based analysis of cavity well performance were used to better understand the downhole conditions responsible for this success, and to determine how these conditions differ from those of fracture stimulated wells.
Comparison of Water Saturations from Capillary Pressure Measurements with Oil-Base-Mud Core Data Ivishak (Sadlerochit) Reservoir, Prudhoe Bay Field
Authors: Richardson J. G. , Holstein E. D.
Published: December 2007

Oil-base-mud cores (OBC) were used as the method for determining water saturations (Sw) in the Ivishak (sometimes referred to at the Sadlerochit) Reservoir of the Prudhoe Bay Field. As-received Swobc ranged from less than 1% to 56% PV. A large alternate centrifuge capillary pressure database was developed to provide an independent check of the OBC results. Development of this database required selection of samples statistically representative of rock types in the reservoir and laboratory techniques that produced reliable results. Comparing Swpc to Swobc values required the consideration of the burial and hydrocarbon accumulation histories and the variations in hydrocarbon properties within the reservoir. This paper discusses the excellent agreement between the two data sets when all pertinent variables are considered.
IFT and Flushing Studies to Validate as-Received Oil-Base-Core Water Saturations from the Ivishak (Sadlerochit) Reservoir, Prudhoe Bay Field
Authors: Reed R. L. , Humphrey R. A. , Holstein E. D. , Rathmell J. J.
Published: December 2007

As-received oil-base-core water saturations were used as the primary source of data for determining Sw for the Ivishak Reservoir (also referred to as the Sadlerochit Reservoir), Prudhoe Bay Field. These saturations varied from < 1% PV to 56% PV. Considerable work was done to validate the reliability of these data. This paper describes laboratory experiments, namely IFT measurements and core flushing studies, done to determine the affect a certain variables on the effect of mud filtrate invasion on resident water saturations. The IFT work suggested no movement of connate water would result from filtrate invasion although at extreme boundary conditions, the possibility could not be eliminated. The flushing studies indicated that at a range of conditions that may exist during coring, there is < 1 water saturation unit change in Sw caused by filtrate invasion.
Simulation Model for Predicting Placement of Gels
Authors: Stavland Arne , Kvanvik B. A. , Lohne Arild
Published: December 2007

This paper describes a simulation model for gel placement. The model is a modified UTCHEM simulation model. Experimental data including retention, gelation strength and gelation rate are matched with the model. It has been stressed that the same set of input data are used in the simulations of the different experiments. The retention of the crosslinker can be crucial and is described by the dissolution of carbonate minerals in the reservoir. In shut-in treatments, gelation strength is found to increase as the permeability increases. Gelation or aggregation is also described during a continuos injection.
Evaluation of Correlations and Parachors To Predict Low Interfacial Tensions in Condensate Systems
Authors: Fawcett M. J.
Published: December 2007

Gas-condensate relative permeability curves are enhanced when the interfacial tension (IFT) is low. Parachor methods generally give poor predictions in the low IFT region. The paper presents new IFT, density, and composition data from a model six component gas-condensate, and IFT and density data from a rich reservoir gas-condensate. Low IFTs were collected using a laser light scattering technique. Single component, multicomponent, and reservoir fluid data were used to evaluate density based IFT correlations. Improved Stegemeier-Hough single component parachors, and parachors for crude oil cuts were derived.
Gas/Oil Capillary Pressure: Measurements at Reservoir Conditions and Effect on Gas-Gravity Drainage
Authors: Longeron D. G. , Kalaydjian François , Bardon Charles , Desremaux L. M.
Published: December 2007

Predictions of oil recovery by immiscible gas injection require accurate laboratory determination of gas-oil capillary pressures. Two series of drainage capillary pressure measurements were performed on sandstone core samples with and without connate water saturation. Binary mixtures of methane/n-heptane at different equilibrium pressures were used to obtain wide variations in the gas- liquid interfacial tensions (IFT) values.

Measurements have shown that the gas-oil capillary pressures determined at different levels of IFT and without connate water can be transformed into one capillary pressure function (Pc/IFT) down to IFT = 3.7 mN/m. Below this value, the capillary pressures measured were significantly lower than those estimated by the Young- Laplace equation. In the presence of connate water, the gas-oil capillary pressures were always higher than the ones measured without water saturation.

The impact using measured instead of scaled capillary pressures from mercury-air data was evaluated through numerical simulations of free gas-gravity drainage on a one meter-long block of a fractured reservoir. Simulations have shown that the kinetics and the level of oil recovery are very sensitive to the capillary pressure curves used as input data. For low IFT values and without connate water saturation the oil recovery is underestimated by about 6% PV using scaled capillary pressures from mercury-air data.

An opposite variation is observed in presence of connate water saturation.
A Laboratory Investigation of Gravity Drainage/Waterflood Interaction in Prudhoe Bay
Authors: Espie A. A. , Brown C. E. , Narayanan K. R. , Wilcox T. C.
Published: December 2007

The Prudhoe Bay reservoir has a number of different oil recovery mechanisms operating in different parts of the field - gravity drainage, waterflooding, miscible flood and vaporisation. The boundaries between the different processes are not fixed, but have moved as the individual processes have matured in the reservoir. One of the key challenges in the management of the field is understanding the interactions that occur between different mechanisms.

One such interaction is that between the upstructure gravity drainage process and the peripheral waterflood. Interpretation and management of reservoir response in this region requires characterisation of the three phase displacement process as water displaces oil in the presence of a high gas saturation.

The aim of this study was to establish and interpret laboratory data quantifying the dynamics of oil bank growth during waterflood/gravity drainage interactions on the core scale. Advanced saturation monitoring was used to monitor the development of the oil bank. Novel tracer techniques were developed to measure transient oil saturations under three phase conditions. Detailed comparison of the core displacements with the predicted behaviour was performed using simulation.
Low-Temperature Analogs of High-Temperature Water/Oil Relative Permeabilities
Authors: Kumar Mridul , Inouye T. A.
Published: December 2007

Dynamic-displacement experiments were conducted to develop and evaluate a simpler low-temperature analog of the high-temperature relative permeability data. Results show that a low-temperature analog of the high-temperature relative permeabilities can be obtained if the water/oil viscosity ratio at the two temperatures and wettabilities are similar. Furthermore, measured endpoint saturations were found to be independent of temperature and predominately a function of viscosity ratio. Using our data and numerical/analytical calculations we show that the observed temperature dependency of endpoint saturations are primarily measurement artifacts caused by viscosity ratio effects.
Gas/Oil Relative Permeabilities and Residual Oil Saturations in a Field Case of a Very Light Oil, in the Near-Miscibility Conditions
Authors: Bardon Charles , Longeron D. G. , Baudoin Francis , Delhomme Abdelkader , Naili Nabil
Published: December 2007

The Hassi-Messaoud Field is one of the biggest oil fields in the world, made to produce by miscible gas flooding since 1964, a few years after the beginning of production. In some blocks, the pressure decline has been very great and such that pressure is currently close to the minimum miscibility pressure (MMP).

Laboratory studies were undertaken on representative core samples with the reservoir fluids to determine the gas/oil relative permeabilities and residual oil saturations (Sorg) at different levels of pressure, below the MMP. The recombined oil samples were prepared with the same stock tank oil and two separator gases, one of them containing significantly more intermediates than the other. The two recombined oils had the same bubble-point pressure. The MMP was measured for these two different oils with an injection gas called "medium gas", produced on the field itself.

The high sensitivity of the MMP to the associate gas composition has been outlined. The Sorg values were very low (between 25 and 5% PV) depending on the initial oil composition and on the level of pressure. A correlation has been established between the observed Sorg and the difference between the pressure of each test and the MMP versus the MMP. Finally, this study has demonstrated that the gas flooding process is very efficient even if the miscibility is no longer reached, while staying however in near miscibility conditions.
Dynamic Validation of Phase Behaviour Models for Reservoir Studies of Gas Injection Schemes
Authors: Khazam M. M. , Danesh Ali , Tehrani D. H. , Todd A. C. , Burgass R.
Published: December 2007

Compositional models based on cubic equations of state (EOS) are generally employed for simulation of the reservoir performance in gas injection processes. Tuning of the EOS to experimental equilibrium data generated at static conditions, PVT data, prior to its use for compositional studies is the current practice in the oil industry. The displacement of oil in a slim tube by the injection gas simulates the phase behaviour resulting from the continuous contact between the two phases in the reservoir more realistically than any other laboratory tests. It has therefore been suggested that the comparison of the displacement data with simulated results of a compositional model using the tuned EOS can be employed to evaluate and, if necessary, further tune the phase behaviour model. As the flow parameters and numerical methods incorporated in the simulation model can strongly affect the prediction results, the value of such an exercise has been seriously questioned.

A systematic study of the applicability of the gas-oil displacement data for tuning of the phase behaviour model to simulate gas injection processes was conducted in this study. The flow characteristics of a number of slim tubes packed with glass beads were evaluated by displacing binary oil mixtures with equilibrated gases to measure the relative permeabilities of the phases at no mass transfer conditions. A large amount of data at different interfacial tension values were used to develop relative permeability-saturation correlations as a function of the interfacial tension. Liquid-Liquid displacement tests were conducted to measure the physical dispersion in the slim tube. The information was used to select the grid block/time step size of the simulator to match the numerical dispersion, due to the truncation error, to that of the physical dispersion.

The reliability of the developed parameters was confirmed by comparing predicted and measured displacement data using multicomponent and real reservoir fluids at no mass transfer conditions.

Having identified all the parameters of the slim tube and simulation model, a series of gas-oil displacements were conducted using multicomponent and real reservoir fluids at miscible and immiscible conditions. The fluids were initially tested at static conditions and the generated experimental data were used to tune the phase behaviour model prior to simulation of the dynamic gas injection tests.

The simulated displacement results, for miscible and immiscible conditions, matched the experimental data favourably where the tuned model was capable of adequately predicting the static data covering the whole range of compositional variations. The study highlighted the value of displacement data for evaluating phase behaviour models particularly at conditions where significant mass exchange occurs between the phases.
Laser Light Scattering Studies of Natural Gas Hydrates
Authors: Nerheim A. R. , Svartaas T. M. , Samuelsen E. J.
Published: December 2007

Nucleation and growth of gas hydrate crystals have been investigated using Photon Correlation Spectroscopy (PCS). Hydrate experiments were performed using distilled and filtered water together with a gas mixture which forms hydrates of structure II (94 mol% methane and 6 mol% propane). Several different pressures and temperatures were investigated and the particle sizes measured during gas hydrate nucleation ranged from 2 nm to 80 nm, approximately, depending on the magnitude of the driving force.

Experiments were performed on both static and moderately stirred systems. The static experiments were difficult to reproduce both with respect to induction time and required driving forces. However, in the stirred experiments the reproducibility was much improved, especially at low temperatures.
Steam Heating of Fractured Formations Containing Heavy Oil: Basic Premises and a Single-Block Analytical Model
Authors: Pooladi-Darvish Mehran , Tortike W. S. , Farouq Ali S. M.
Published: December 2007

Interest in modeling thermal processes in naturally fractured reservoirs containing heavy oil has grown considerably because of encouraging results from experimental and theoretical studies as well as pilot tests. However, satisfactory predictive models are still lacking. This paper examines one component of such a model by studying a single block of a naturally fractured reservoir under steam injection, and presenting analytical solutions for heat flow and non-isothermal gravity drainage from the block.

The fracture-matrix heat transfer is investigated first by analyzing the governing differential equations. It is found analytically that for a typical matrix block in the steam zone, the transient temperature distribution within a single block is not affected by convection. For physical properties other than those considered in this paper, it is shown that evaluation of the Peclet Number indicates the order of error that will be introduced if convection is neglected. This is found to be in the order of 1% for a typical fractured carbonate reservoir. Next, an integral method is used to obtain the transient temperature distribution within the block, which can be used directly for the heat consumption calculations. The temperature distribution is incorporated into an analytical equation to obtain the thermal drainage rate under gravity flow. The final equation is a relation between the physical properties of a single block and the flow rate in an easy-to-calculate form. The solution of the problem shows that using oil viscosity at average block temperature is adequate for recovery calculations during the heating period. These findings can be used in single block and fieldwide modeling of heat and fluid flow in fractured reservoirs, such as those in the Middle East.
Improving the Potential to Produce Oil from Naturally Fractured Reservoirs
Authors: Perez Jorge M. , Poston S. W. , Berg R. R. , Friedman M. , Gangi A. F. , Nighswander J.
Published: December 2007

A multi-phase effort that involved geological, geophysical, and petroleum engineering studies yielded an improved understanding of naturally fractured reservoirs and potential manners to improve the incidence of oil production from such reservoirs.

Maps of fracture traces on bedding planes in the Austin Chalk outcrops showed organized trends of the fracture development and a hierarchical nature within the complete fracture system.

Vertical Seismic Profile, VSP data has been used to estimate fracture orientation from shear-wave splitting.

Well log responses in Austin Chalk wells have shown to be a reliable indicator of organic maturity. Well logs have also been used to calculate average resistivity of producing zones and to correlate resistivity with oil saturation and therefore with producing potential.

Additionally, the use of carbonated water imbibition displacement processes has shown encouraging results of accelerating and increasing oil recovery of oil which do not have appreciable asphaltene contents.
Theoretical/Experimental Considerations About Oil Displacement by Water in a Fractured Porous Medium
Authors: Perez-Rosales Candelario , Cruz-Hernandez Juana , Samaniego-V Fernando
Published: December 2007

Based upon observations made with a two-dimensional porous cell, which allows direct visualization of fluid displacement processes, theoretical formulations were established for explaining oil displacement by water in a fractured porous medium. The theory rests on the idea that fluids are transported essentially through the fractures by a convective process, whereas water inflow to the matrix blocks is carried out by a dispersive process which depends on the difference between fracture and matrix water saturation. With these considerations, a derivation is presented of an expression for water saturation as a function of distance and time. Agreement between theory and experiment is reasonably good.
Application of a New Scale Up Methodology to the Simulation of Displacement Processes in Heterogeneous Reservoirs
Authors: Durlofsky L. J. , Milliken W. J. , Dehghani K. , Jones R. C.
Published: December 2007

A general method for the scale up of highly detailed, heterogeneous reservoir cross sections is presented and applied to the simulation of several recovery processes in a variety of geologic settings. The scale up technique proceeds by first identifying portions of the fine scale reservoir description which could potentially lead to high fluid velocities, typically regions of connected, high permeability. These regions are then modeled in detail while the remainder of the domain is coarsened using a general numerical technique for the calculation of effective permeability. The overall scale up method is applied to the cross sectional simulation of three actual fields. Waterflood, steamflood and miscible flood recovery processes are considered. In all these cases, the scale up technique is shown to give coarsened reservoir descriptions which provide simulation results in very good agreement with those of the detailed reservoir descriptions. For these simulations, speedups in computation times, for the coarsened models relative to their fine grid counterparts, range from a factor of 10 to a factor of 200.
A Systems Approach to Completing Hostile Environment Reservoirs
Authors: Huntoon G. G.
Published: December 2007

The economics of developing a hostile environment reservoir should be able to support a high front end investment to make a completion commensurate with the risk. A completion scenario which uses current material technology and quality practices can influence the long-term cost of a completion design. A complete economic cost analysis would need to be performed to evaluate various completion scenarios. The well stream composition and reservoir performance data will help define the requirements for material selection and tubular sizing. Realistic quality plans and modem completion practices are necessary to successfully and economically complete current hostile environment wells. Amoco uses a variety of completion scenarios depending on the operating conditions. Amoco's experience using inhibitors and carbon steel in hostile environments has been excellent. With the emphasis on reducing long-term cost, the expanded use of higher alloy tubulars for production liners and tubing has been increasing. Concurrently, wellhead metallurgy and valve configuration has moved toward the higher alloy materials and larger diameters. Extensive planning is necessary to coordinate a successful completion. Good project planning will look at detailed tubular design, wellhead design, specifications and quality plans. One particular aspect of Amoco's tubular design is the use of a tubular quality level (TQL).

The current methodology of completing a hostile environment wells will be discussed from a knowledge base of evolving technology and project and quality planning.
Elimination of Near-Wellbore Tortuosities by Means of Hydrojetting
Authors: Surjaatmadja J. B. , Abass H. H. , Brumley J. L.
Published: December 2007

Near-wellbore tortuosity is one of many conditions that can cause additional friction pressure loss during the injection or production phase of a well. Production pressure loss reduces the potential production capacity of the well. In addition, difficulties with proppant placement are often attributed to the presence of tortuous fracture paths, which can lead to premature screenouts in the fracturing operation.

This paper discusses the importance of proper design and placement of perforations to obtain good fracture initiation. By doing so, optimal well production can be attained. Practical implementations of hydrojetting techniques as a substitute for the shaped-charge perforating process are discussed. The formation of tortuosities and the use of hydrojetting are demonstrated through laboratory tests. Hydrojetting tools that are used to achieve a fracture initiation from deviated or horizontal wells are also discussed.
The Effect of Solids Concentration and Formation Characteristics on Formation Damage and Permeability Recovery
Authors: Ismail Abdul R. , Peden James M. , Arshad Azmi M.
Published: December 2007

An experimental study has been made to investigate the effect of solids concentration and filter media on fluid loss and permeability recovery of cores. KC1- polymer muds of different barite concentrations and different types of core were used to perform the tests.

Filtration tests showed that fluid loss increased as solids concentration in the mud increased. Increasing the solids concentration in the mud appears to improve permeability recovery when the cores were backflushed. However, high spurt loss and poor permeability recovery were observed if muds containing polymer materials were used without the addition of solid particles.

Filtration and permeability restoration are not only affected by the size, shape and solids concentration in the mud but also to the pore size distribution and core characteristics. Detailed observation using scanning electron microscope was used to identify the solids impairment at the core face. Therefore, to reduce formation damage and improve recovery, suitable size, shape and concentration of solids in the mud must be properly selected.
Reservoir Saturation Determination in the Eromanga Basin Using Carbon/Oxygen Logging
Authors: Goode P. A. , Sibbit A. M. , Looi S. Y.
Published: December 2007

The Jurassic oil reservoirs of the Eromanga Basin in Central Australia can be characterised as having high permeability and strong aquifer influx. The problem of determining which zones in a well have been swept is difficult due to the very low salinity (<2,000 ppm) of the formation water. Traditional methods of pulsed neutron capture are not suitable at such low salinity. Carbon/Oxygen (C/O) pulsed neutron logging tools which were introduced to address this particular problem were hampered by several short comings including large tool size, slow logging speeds and sensitivity to the borehole fluid. Recently a new generation of C/O tools have been in-troduced which permit faster logging speeds, less de-pendence on borehole fluids and can operate through tubing.

This papef presents several examples of the use of C/O logging in the Eromanga Basin and describes how the results have been used to identify potentially unswept oil pools for exploitation. A comparison with the older-generation tools is discussed and the advantages of the new tools highlighted. The results obtained from the C/O logging are verified with subsequent production data and standard logging suites run in offset wells.
The Effect of Temperature in Sweet Corrosion of Horizontal Multiphase Carbon Steel Pipelines
Authors: Vuppu A. K. , Jepson W. P.
Published: December 2007

The effect of temperature on sweet corrosion in carbon steel pipelines at different liquid velocities under various oil-water concentrations was studied. Carbon steel coupons were used to study the corrosion products formed. With an increase of temperature up to 60 C, corrosion rate increases. Above 60 C, protective carbonate layers were observed. At lower temperature and pressures, the corrosion rates are similar to those predicted by de Waard and Milliams. With an increase in temperature, the corrosion rate increase is more pronounced at higher pressures and is greater than the de Waard and Milliams. No maximum in the corrosion rate is seen for oil water mixtures for temperatures up to 80 C.
Trials of a Gamma-Ray Multiphase Flow Meter on Oil Production Pipelines at Thevenard Island
Authors: Roach G. J. , Watt J. S. , Zastawny H. W. , Hartley P. E. , Ellis W. K.
Published: December 2007

CSIRO has developed a gamma-ray multiphase flow meter (MFM) for the on-line determination of the flow rates of oil, water and gas in oil production pipelines. It is based on two gamma-ray transmission gauges mounted on a pipe carrying the foil flow of the multiphase fluid.

In trials, two of these MFMs were mounted on a test pipeline linking the test manifold to the test separator at the oil processing facilities on Thevenard Island. One MFM was always mounted on the vertical upflow section of the pipe. The other was in turn mounted on the vertical downflow section, and on two horizontal sections with different upstream conditions.

The MFM mounted on the vertical (upflow) pipeline determined the flow rates to 4.0% relative for liquids, 7.5% for oil, 4.5% for water and 7.9% for gas. Water cut was determined to 3.6% relative. The MFM mounted on the vertical downflow pipeline determined flow rates to 3.3% relative for liquids, 6.1% for oil, 4.5% for water, and 7.7% for gas. Water cut was determined to 3.7%.