bluuebunny/crossref_metadata_2025 huggingface dataset:
In-Depth Permeability Damage by Particle Deposition at High Flow Rates
Authors: Veerapen J. P. , Nicot B. , Chauveteau G. A.
Published: December 2007

This paper reports the main results of a study of the physics of in-depth particle deposition inside porous media at high velocities. This study was motivated by the need to determine the equations relevant for the deposition of "large" micronic-size particles to introduce them into a numerical simulator and thus to be able to predict more reliably well injectivity decline. Indeed, as distance from the well decreases, velocity increases and convection becomes dominant over brownian diffusion at smaller and smaller length scale. This changes drastically the deposition laws and consequently those of permeability damage. Indeed, at high velocities, convection is expected to reduce drastically particle deposition density near pore throats by two mechanisms we refer to as hydrodynamic shadowing and surface entrainment. Our analysis shows that hydrodynamic shadowing may be active up to relatively large distances from the wells for micronic-size particles. A direct consequence is that equations based on convective diffusion at pore length scale are irrelevant. Indeed, hydrodynamic shadowing hampers deposition of new arriving particles downstream from already deposited ones, leading to a very significant reduction in maximum deposition density. This prediction is in good agreement with our experimental results. The second mechanism, namely surface entrainment, is limited to much smaller distances from the wells but also contribute to reducing injectivity damage. In this surface entrainment regime, particles can move on non-negligible distances near the pore throats before being attached by attractive surface forces. As a result, deposition probability in pore throats is smaller than predicted from conventional analysis and decreases with velocity. These two mechanisms may explain why the formation of internal cakes, which is initiated by pore bridging, is often observed at low velocity but rarely in the high velocities range. Such a drastic effect of flow velocity suggests that, in field injections, internal cakes may be initiated only in-depth far inside the reservoir, grow up towards the well and then cause very severe and irreversible injectivity damages. A third point, particularly important for modeling permeability damage kinetic, is that the particle deposition flux is several times higher onto pore throats than the mean value. Such a result is expected only in a converging flow but not in a flow over a collector. This confirms that the prediction of transport phenomena requires the use of a dual porous medium model such as the Grain-and-Pore-Throat model which accounts for both flow-over and flow-through situations which are obviously two characteristics of flows through porous media.
Laboratory Device for Testing of Delayed-Breaker Solutions on Horizontal Wellbore Filter Cakes
Authors: Todd Brad , Murphy Rob
Published: December 2007

Many high-permeability, soft sandstone formations are completed with horizontal wellbores. In these formations, completions are typically openhole with screens or screens combined with gravel packs. The drill-in fluid filter cake is left in place until the completion operations are finished. At that time, a cleanup solution is pumped to remove the filter cake from the wellbore face. These cleanup solutions can be acids, chelating agents, oxidizers or enzyme treatments, or combinations of these materials. A common disadvantage of these treatments is that they are highly reactive and may remove the filter cake at the point of circulation before the treatment can be placed over the entire openhole interval. This is especially true for the cleanup solution used to address the bridging particles in drill-in fluids. A need exists for cleanup solutions that have a delayed effect on filter-cake integrity, allowing the cleanup solution to be circulated across the interval before leakoff to the formation becomes a problem. Ideally, the treatment's reaction with the filter cake would commence when the entire solution is in place and continue until the filter cake is uniformly removed. If a sufficient delay is possible, the breaker solution can be placed with a gravel pack. Break times for this situation would range from 4 to 24 hours, depending on the need for fluid-loss control during subsequent pipe trips.

Conducting breaker tests manually for this type of delay could be extremely time-consuming and prone to variations between tests. Repeatability of the filter-cake deposition becomes even more important during sensitivity testing of the various components of a proposed cleanup solution. Clearly, automating the filter-cake construction and breaker solution testing would be advantageous. Fortunately, commercially available dynamic mud-filtration testing equipment can provide much of the needed automation capability. This paper discusses the additional modifications necessary for converting the instrument into the automated, delayed-breaker testing device required. Example test results are given for long-delayed breaks of water-based drill-in fluid filter cakes showing the sensitivity of the break time as a function of various formulation and testing parameters.
Polymer Sealant for Unwanted Gas in Openhole Gravel-Pack Completion
Authors: Bach T. , Wennberg K. E. , Mebratu A. , Hendriks W. P. , Warren J. M. , Rolfsvaag T.
Published: December 2007

In September 1999, Statoil completed Well A-13 in the Are formation ofthe Heidrun field with a 130-m openhole gravel pack. After only a few days of production, a high gas-to-oil ratio (GOR) required the operator to shut the well in. Free gas was believed to be flowing from a gas-filled sand located immediately above the 9 5/8-in. casing shoe. Production analysis indicated a high-permeability flow channel between this layer and the upper zone of the gravel pack. The operator and a major service company jointly evaluated different chemical gas shut-off systems and several placement methods. A new generation of organically crosslinked polymer gel technology was selected. In addition, the operator desired that the gel be injected with open-ended CT and without mechanical packers to reduce operational risk. Therefore, a chemical diversion system was required for protecting the lower zone.

In February 2000, a temporary blocking agent consisting of a crosslinked hydroxypropyl guar polymer was placed in the lower part of the gravel pack. Then, the permanent sealant was injected into the gas-producing zone. After 72 hours, CT was used to wash the well. Finally, the well was lifted with production gas. The entire operation was completed in a single run with CT.

Currently, the well is producing oil at a rate of350 Sm3/d and no significant free gas. Production paid for the cost of the sealant treatment within 1 month. Additionally, this treatment prevented the operator from having to recomplete and sidetrack the well. This paper describes the well's gas-flow mechanism, the polymer gel systems used for sealing the gas-flow zone, the placement technique, and the operational aspects of the selective gas shut-off treatment.
Recovery Increase through Water Flooding with Smart Well Technology
Authors: Brouwer D. R. , Jansen J. D. , van der Starre S. , van Kruijsdijk C. P. J. W. , Berentsen C. W. J.
Published: December 2007

Water flooding is a frequently used technique to increase oil recovery after primary depletion. The presence of high permeability zones can have a large influence on the recovery, because they can cause early water breakthrough and trapping of by-passed oil. Smart well technology gives us the opportunity to counteract these effects by imposing an appropriate pressure or flow rate profile along the injection and production wells. In the current study we focus on water flooding with fully penetrating, smart, horizontal wells in 2 dimensional, horizontal reservoirs with simple, large-scale heterogeneities. The water flood is improved by changing the well profiles according to some simple algorithms that move flow paths away from the high permeability zone in order to delay water breakthrough. For all cases where early water breakthrough plays a role, it was possible to improve the water flooding process with these simple algorithms. For all these cases acceleration of production was possible. The increase in ultimate recovery obtained is very much dependent on total production time allowed. The shorter this time, the better the improvement in recovery will generally be. The increase in recovery obtained by applying the optimization algorithm varied between 0% - 20%. The delay in breakthrough time achieved by our optimization routine varied from 7-168 %. Our algorithms result in flow profiles that do not change in time. Both results from our own study and from literature show that time-varying flow profiles can at least further accelerate production. The general principle behind optimization in our cases was to reduce the difference in time of flight from injector to producer as much as possible.
Drainage Area for Horizontal Wells With Pressure Drop in the Horizontal Section
Authors: Saavedra N. F. , Reyes D. A.
Published: December 2007

In general, a horizontal well is more productive than a vertical well, due to the fact that there is a larger area of contact with the reservoir and that there is less pressure drop per unit of length in the production section.

The two main factors to obtain more reserves in a reservoir are the increase in drainage area or an increase of the recovery factor using some enhanced recovery method. The productivity as well as the drainage area of a horizontal well may be limited by the pressure drop within the wellbore, especially when the pressure drop is comparable to the drawdown from the reservoir to the wellbore. Over the past few years, horizontal well technology has acquired quite significant importance and thousands of wells are drilled around the world every year, which is why there is a need for more information on the factors that affect pressure drop within the well.

Total pressure drop in horizontal wells has been analyzed in terms of four separate effects: wall friction, flow acceleration, perforation roughness, and fluid mixing.1 Thus, the pressure drop in horizontal wells is made up of a gravity term, a frictional term and another due to flow acceleration.2

The literature available about calculating drainage areas of horizontal wells only covers geometric methods, which assume that the horizontal well drains an elliptic area or a combined area made up of a central rectangle and two semicircles on the ends. 2,3

This paper proposes an expression to calculate the drainage area of horizontal oil wells that produce at high reservoir flow rates, exhibiting a frictional pressure drop throughout the wellbore between 15 to 60% of the reservoir drawdown at the heel of the well.
Artificial Neural Networks Applied to the Operation of a Fluid Catalytic Cracking (FCC) Unit
Authors: Pérez José R. , López Roberto , Dassori Carlos G. , Ranson Aaron
Published: December 2007

A model, based on artificial neural networks (ANN), for a fluid catalytic cracking (FCC) unit is developed.

The ANN model of the plant was developed using process and laboratory data directly from a refinery data acquisition system. And it used to predict process variables and estimate several product quality properties. The empirical model was accurate up to 98.0 % when tested on experimental data not used during training, which is an outstanding performance.

The present paper shows how a neural network, three-layered perceptron, can be used effectively to simulate the actual behaviour of refining units, specifically a fluid catalytic cracking (FCC) unit.
Prediction of Formation and Downhole Pressures by Using Computer Intelligent Calculation and Analysis
Authors: Zhou Lei , Zhou Kaiji
Published: December 2007

Formation pressure, failure pressure, wellbore collapse pressure and surge/swab pressure are important basis of pressure control in drilling progress, wellbore stability, balanced and unbalanced drilling, and well structural design. They are also fundamental data used in Drilling Engineering Design and Construction. Comprehensive well logging (sound logging, density logging, gamma logging) can be collected and handled intellectually by this system. Formation pressure, failure pressure, wellbore collapse pressure, and rock characteristic factor (dynamic elastic modulus, static elastic modulus, Poisson ratio, internal friction angle, effective stress modulus, shear strength, compressing strength, tensile strength) were predicted by this system. In this paper, calculation and analysis system to predict transient-state, pseudo-transient-state and steady-state pressure fluctuations were established by using theory of elastic liquid column and rigid liquid column (Three types of fluids, Bingham fluid, power law fluid, H-B fluid, were included in this system). This prediction system has the following features: Capacity to collecting and handling well logging curves intelligently; High accuracy to predict; Output pressure curves and pressure gradient curves also regression results. This prediction system can provide Drilling Engineering Design, working-on, balanced and unbalanced drilling, overflow and leaking control, safe trip in and trip out velocity, and wellbore stability with reliable data.
Well Impairment During Sea/Produced Water Flooding: Treatment of Laboratory Data
Authors: Bedrikovetsky P. , Marchesin D. , Shecaira F. , Serra A. L. , Marchesin A. , Rezende E. , Hime G.
Published: December 2007

Severe fall of injectivity happens with the reinjection of produced water which contains oil droplets and solid particles, with the injection of sea water in offshore fields which contains organic and mineral inclusions, and in a general case of injection of a poor quality water.

The mathematical model contains two empirical functions - filtration coefficient versus concentration of deposited particles and velocity and formation damage function versus concentration of deposited particles. Two inverse problems for determination of these two functions from the laboratory coreflood test are formulated.

The first problem is determination of a filtration coefficient from the concentration history on a core outlet. The algorithm of solution is given, and the laboratory data treatment is presented. The second problem is determination of a formation damage function from the pressure drop history on a core. These two methods allows to determine from laboratory test the information necessary for prediction of well impairment.
Improvement Tools To Solve Quality Deviation Problems
Authors: Grzona Gabriel C.
Published: December 2007

One of the fundamental requirements for success in making a process function under the concepts of Total Quality Management is to ensure that it is capable of operating with a minimum variability with respect to the quality specification objectives of the products which are produced by the process.

Quality may be broadly defined in many ways, but from a strictly technical viewpoint Quality Engineering must be understood as the skill to reduce systematically the variability of the processes. It is in this context in which the Continuous Improvement Tools and particularly the Statistical Process Control, are essential for achieving World Class Quality Management.

A program for the application of these tools can detect assignable causes, limit waste, improve the quality of the products, reduce or eliminate reprocessing and, even more important, establish a new process of systematic work toward continuous improvement.

The present job shows both theoretically and practically how to apply these tools to solve quality deviations.

Case Study: Improvement of Jet A1 quality in a Hydrocracking unit.

Background

During the last few years quality systems have become established as a fundamental part of business strategies to increase the productivity and competitiviness of companies. Total Quality Managements focus their attention on their most precious treasure : "THE CUSTOMER". If a product is to meet the client s acceptability criterion its quality must inexorably be stable and reproducible, although even then there is no total guarantee that the product will have the same quality. All processes have a certain degree of variability : when the latter is "natural" it is due to the cumulative effect of small effects which are known as "inevitable causes". In Statistical Control jargon this is referred to as a system of accidental or random causes.

A system which performs with only accidental causes is said to be under "Statistical Control".

On the other hand if "assignable causes" appear in a process, that is, those that derive from a perfectly detectable source of lack of control, then the use of the continuous improvement tools is fundamental for their correction.
Evolution of Field Rejuvenation
Authors: Singh Kasarie
Published: December 2007

At the state oil company of Trinidad and Tobago, (Petrotrin) and its predecessor companies, Field Rejuvenation has evolved through time from single well targets to the more highly detailed and complex field reservoir characterization project currently underway.

Initially single well target selection would be done by individual engineers operating their specific field. Generally, the benefit of these actions were not long term and did not significantly affect or arrest the declining production trends. At a more formal level there were studies undertaken in the process of the implementation a secondary or enhanced oil recovery project. This had the effect of arresting field declines and improving overall recoveries in the target fields.

The foregoing activities were carried out by the operating companies of the day. In the late eighties because of limited capital resources, a program of leasing blocks of idle wells to small independent local operators was initiated. This program proved successful in increasing indigenous oil production from idle assets as well as generating positive cash flows. It was therefore expanded and has since included farmouts and joint-venture arrangements with foreign companies participating also.

Currently Petrotrin is concluding a detailed field reservoir characterization study of one of its most mature fields on land which began production in 1913. The preliminary results have demonstrated the crucial role of reservoir characterization in evaluating the true potential of mature fields, and its potential for increasing production even from these fields.
U.S. International Minerals Policy in the 1970's (These are the personal views of the author and do not necessarily represent the policy of the U.S. Government)
Authors: Garten Jeffrey E.
Published: December 2007

Garten, Jeffrey E., former member, Policy Planning Staff U.S. Department of State Staff Member, Economic Policy Group Executive Office of the President

An appraisal of the role played by imports of critical mineral materials in shaping U.S. foreign policy during the current decade, with particular emphasis on the importance of energy particular emphasis on the importance of energy and minerals in U.S. trade patterns with economically less developed nations.

Introduction

This paper will discuss three elements of U.S. international minerals policy - the international minerals environment, the government's objectives, and the imperatives for U.S. policies

A. The Environment

In the last several years, we have seen first, tight supply situations and soaring prices for a number of critical industrial raw prices for a number of critical industrial raw materials; and, then, rapidly declining prices; we have witnessed the determined and economically disruptive action of the OPEC cartel; we have experienced recurrent resort to unilateral barriers to raw material exports; and we have heard predictions of natural resource exhaustion.

These events have, of course, colored the public debate over U.S. raw materials policy. public debate over U.S. raw materials policy. But the emerging U.S. government policy itself is less a response to any particular event or scare in the last year or two, than to longer term trends which are occurring in the international economy and in the minerals markets.

Let us set aside predictions of natural exhaustion of resources. The government's feeling is that if resource scarcity occurs it will be because of improper public policies and not natural depletion. The following considerations, however, are strongly influencing U.S. foreign economic policy.

First, it is quite possible that several structural changes are occurring in the world economy which will have a major impact on minerals markets. Many economists are concerned that a de facto synchronization of the business cycle in industrial countries will result in recurring and possibly more severe business cycles than the recent period we have just been through. The result would be reflected in greater global demand surges and contractions and, hence, wider price swings. There is a concern also that we have entered a period of structural inflation which among other things will continue to encourage commodity speculation and continue to bid up raw material prices. There is the growing interdependence among many countries, which means that we are all drawing on one global resource base; insures that even many temporary economic disturbances will be transmitted quickly from one economy to the rest; and makes foreign policy reach to our gas pumps, our food counters, and the aluminum pumps, our food counters, and the aluminum siding on our garages. And there have been major changes in the relative economic relationships between countries.
How Fluid and Rock Properties Affect Production Rates in a Heavy-Oil Reservoir Cerro Negro, Venezuela
Authors: Lugo R. Garcia , Eggenschwiler M. , Uebel T.
Published: December 2007

In Cerro Negro, extra-heavy crude (8.5° API) is produced using horizontal wells via cold production from Miocene Morichal Member sands. Production is from an average depth of 3,000 ft, with an in-situ viscosity of around 2,000 cp (@140° F). The Morichal Member is sub-divided into three informally defined units: Upper, Middle and Lower. Reservoir quality is excellent, with porosity around 32% and permeability in the order of 10 Darcies.

The top of the Morichal sands varies in depth from 1,500 to 4,000 ft. The depth of the sand, coupled with 700-900 ft reservoir thickness, results in significant changes in pressure and viscosity across the block. Pressure varies from 900-1,300 psi and viscosity from 1,500-4,000 cp. Pressure and viscosity variations, when modeled using a single well simulation grid, significantly affect well productivity and ultimate recovery. Changes in viscosity and pressure, assuming constant pay thickness, and permeability, result in predicted ultimate well recoveries that vary from 1.5 to 6 million barrels of oil per well. Efforts to history match horizontal wells that have been on production for around one year have been successful. These results give a better understanding of how fluid and rock properties are influencing extra-heavy crude oil recovery, which allows a better prediction of well productivity and full-field development plans.
Surrogate Modeling-Based Optimization of SAGD Processes
Authors: Queipo Nestor V. , Goicochea P. Javier V. , Pintos Salvador
Published: December 2007

This paper presents a solution methodology for the optimization of geometrical and operational parameters of SAGD processes in a heterogeneous and multiphase petroleum reservoir. The optimization refers to the maximization or minimization of performance measures such as net present value, cumulative oil production or cumulative steam injected.

The solution methodology includes the construction of a "fast surrogate" of an objective function whose evaluation involves the execution of a time-consuming mathematical model (i.e. reservoir numerical simulator) based on neural networks, DACE modeling, and adaptive sampling. Using adaptive sampling, promising areas are searched considering the information provided by the surrogate model and the expected value of the errors.

The proposed methodology provides a global optimization method, hence avoiding the potential problem of convergence to a local minimum in the objective function exhibited by the commonly Gauss-Newton methods. Furthermore, it exhibits an affordable computational cost, is amenable to parallel processing, and is expected to outperform other general-purpose global optimization methods such as, simulated annealing, genetic algorithms, and pattern search methods.

The methodology is evaluated using a case study with vertical spacing, steam injected enthalpy, injection pressure and subcooling as the sought parameter values in a SAGD process that optimize a weighted sum of cumulative oil production and cumulative steam injected for a selected reservoir. From the results, it is concluded that the methodology can be used effectively and efficiently for the optimization of SAGD processes. In addition, the optimization approach holds promise to be useful in the optimization of objective functions involving the execution of computationally expensive reservoir numerical simulators, such as those found, not only in oil recovery processes, but also in other areas of petroleum engineering (e.g. hydraulic fracturing).
Mechanistic Modeling of Solution Gas Drive in Viscous Oils
Authors: Arora P. , Kovscek A. R.
Published: December 2007

Solution gas drive in reservoirs containing heavy and viscous oil is not well understood. This paper develops a mechanistic population balance model for describing the process of bubble nucleation and growth. The model is applied to both light and viscous oils. The primary modeling concept is a continuum bubble population balance. Appropriate rate equations are derived for two theories of bubble nucleation described in the literature—instantaneous nucleation (IN) and progressive nucleation (PN). The results of simulations for the IN and PN models are compared to experimental data reported elsewhere for light oil and to new data for viscous oils. Model parameters are all physically based. Within the IN model, the number density of bubbles must be specified while the PN model requires the cavity size distribution of the porous medium as input. The PN model matches the experiments somewhat better, but is more demanding computationally. Interestingly, the population balance description of either model does not require a critical supersaturation to be exceeded before the onset of bubble nucleation and growth. Supersaturation is the difference between the equilibrium and dynamic liquid pressure of a system. Liberation of gas from solution at the thermodynamic bubble point and the bubble growth equations presented here well describe the kinetics of the gas phase and pressure response of the systems examined.
Thermodynamic Characterization of a PVT of Foamy Oil
Authors: Romero Douglas J. , Fernandez Belkis , Rojas Gonzalo
Published: December 2007

This work is based on theoretical studies and/or experimental observations carried out diverse authors whom have investigated on the "foamy oil phenomenon" developing a methodology to characterize these crude oils thermodynamically, taking as bases nonconventional PVT analysis and using as research tool the application of equations of state and methods known for the determination of the equilibrium constants liquid-gas. It is presented two new correlations developed in this work for the calculation of the viscosity of heavy crude oils, which are based on values of molar fractions of liquid and gas in equilibrium. The proposed methodology was validated using conventional and nonconventional PVT data of wells located in the Orinoco Belt, Jobo Field, Morichal Area obtaining excellent results and showing that the proposed methodology is applicable to conventional and nonconventional heavy crude oils in all the possible scenes, that is to say, whether necessary information is available.
Practical Methods to Optimizing Production in a Heavy-Oil Carbonate Reservoir: Case Study From Issaran Field, Eastern Desert, Egypt
Authors: Waheed Arshad , El-Assal Hossam , Negm Ehab , Sanad Medhat , Sanad Osama , Tuchscherer Gary , Sayed Mohamed
Published: December 2007

The Issaran field, a heavy-oil reservoir with reserves of approximately 500 MM bbl of oil, was discovered in 1981. The producing horizons were carbonate formations of Miocene age occurring at an average depth of 2,200 ft. The oil being produced on artificial lift was of 9° to 12° API in a viscosity range of 3,000 to 5,000 cp.

Before mid-1999, nine wells had been drilled in the field with a cumulative production of about 450 BOPD. This field did not command high priority because of its low productivity and the low prices that heavy crude attracts. However, with the oil price increases in 1999 and 2000, the Egyptian government made a concerted effort toward developing this field. New and applied technology provided considerable returns within 1 year of new investments. The field has been producing as much as 1,800 BOPD (a four-fold increase), from five new wells drilled in the area.

Plans were made for thermal recovery in the form of steam stimulation for this heavy-oil reservoir, but first, it was necessary to produce under "cold production." Several industry publications1-3 have addressed cold production, predominantly pertaining to sandstone reservoirs. This paper highlights the experiences, challenges, and practical solutions in optimizing production from a fractured, carbonate reservoir. Several leading-edge technologies and optimization techniques that are effective in less-challenging reservoirs have contributed tremendously to enhancing production from this heavy-oil reservoir. The path to success began with the definition of the reservoir-flow mechanism, optimized perforating schemes, ehnanced carbonate stimulation, and improved completion designs.
Improved Permeability Estimates in Carbonate Reservoirs Using Electrofacies Characterization: A Case Study of the North Robertson Unit, West Texas
Authors: Mathisen Trond , Lee Sang Heon , Datta-Gupta Akhil
Published: December 2007

We propose a simple and cost-effective approach to obtain permeability estimates in heterogeneous carbonate reservoirs using commonly available well logs. Our approach follows a two-step procedure. First, we classify the well log data into electrofacies types. This classification does not require any artificial subdivision of the data population but follows naturally based on the unique characteristics of well log measurements reflecting minerals and lithofacies within the logged interval. A combination of principal component analysis, model-based cluster analysis and discriminant analysis is used to identify and characterize electrofacies types. Second, we apply non-parametric regression techniques to predict permeability using well logs within each electrofacies.

Our proposed method has been successfully applied to the North Robertson Unit (NRU) in Gaines county, west Texas. Previous attempts to derive permeability correlations at the NRU have included rock type identification using thin section and pore geometry analysis that can sometimes be expensive and time-consuming. The proposed approach resulted in improved permeability estimates leading to an enhanced reservoir characterization and can potentially benefit both daily operations and reservoir simulation efforts. The successful field application demonstrates that the electrofacies classification used in conjunction with sound geologic interpretation can significantly improve reservoir descriptions in complex carbonate reservoirs.
Modeling Technique of Asphaltene Precipitation
Authors: Li Min , Guo Ping , Li Shilun
Published: December 2007

Study of three phase equilibrium has been seen from many literatures. Most research on modeling of asphaltene precipitation has remained in qualitative description stage. Even though quantitative calculation of asphaltene precipitation can be seen from some reports. However, quantitative calculation of asphaltene precipitation with three phase flash algorithm is unstable because gas-liquid-solid material balance equations is highly non-linear equations. In the light of general view that there are not heavy hydrocarbons with high molecular weight including asphalt in gas phase, technique of stable asphaltene precipitation calculation is put forward by the paper. The recommended technique in the paper separates gas-liquid-solid equilibrium into two parts: gas-liquid and liquid-solid equilibrium. Liquid phase is a bridge between gas and solid phase and solid precipitates always from liquid phase. Gas-liquid equilibrium is described through EOS and fugacity of asphaltene determined from gas-liquid equilibrium should be compared and accord with fugacity of pure solid phase of asphaltene. In this way, modeling of three phase equilibrium becomes easier and more stable. The validation of the model with experimental data is described also in the paper. Additionally, the paper puts forward gas-liqiud-asphaltene material balance equations which can be deduced from general three phase material balance equations and are not similar to them in forms.
Risk Reduction with a Fuzzy-Expert Exploration Tool
Authors: Weiss W. W. , Balch R. S. , Broadhead R. F.
Published: December 2007

Incomplete or sparse information on types of data such as geologic or formation characteristics introduces a high level of risk for oil exploration and development projects. "Expert" systems developed and used in several disciplines and industries, including medical diagnostics, have demonstrated beneficial results. A state-of-the-art exploration "expert" tool, relying on a computerized data base and computer maps generated by neural networks, is proposed for development through the use of "fuzzy" logic, a relatively new mathematical treatment of imprecise or non-explicit parameters and values. Oil prospecting risk can be reduced with the use of a properly developed and validated "Fuzzy Expert Exploration (FEE) Tool."

This tool will be beneficial in many regions of the US, enabling risk reduction in oil and gas prospecting and decreased prospecting and development costs. In the 1998 - 1999 oil industry environment, many smaller exploration companies lacked the resources of a pool of expert exploration personnel. Downsizing, low oil prices and scarcity of exploration funds have also affected larger companies, and will, with time, affect the end users of oil industry products in the US as reserves are depleted. The proposed expert exploration tool will benefit a diverse group in the US, leading to a more efficient use of scarce funds and lower product prices for consumers.
A Strategy for Attacking Excess Water Production
Authors: Seright R. S. , Lane R. H. , Sydansk R. D.
Published: December 2007

This paper describes a straightforward strategy for diagnosing and solving excess water production problems. The strategy advocates that the easiest problems should be attacked first and diagnosis of water production problems should begin with information already at hand. A listing of water production problems is provided, along with a ranking of their relative ease of solution.

Conventional methods (e.g., cement, mechanical devices) normally should be applied first to treat the easiest problems— i.e., casing leaks and flow behind pipe where cement can be placed effectively and for unfractured wells where impermeable barriers separate water and hydrocarbon zones. Gelant treatments normally are the best option for casing leaks and flow behind pipe with flow restrictions that prevent effective cement placement. Both gelants and preformed gels have been successfully applied to treat hydraulic or natural fractures that connect to an aquifer. Treatments with preformed gels normally are the best option for faults or fractures crossing a deviated or horizontal well, for a single fracture causing channeling between wells, or for a natural fracture system that allows channeling between wells. Gel treatments should not be used to treat the most difficult problems—i.e., three-dimensional coning, cusping, or channeling through strata with crossflow.
A Completion Technique For Overcoming Formation Damage
Authors: Colle Ed A.
Published: December 2007

A technique has been developed to overcome the formation damage of drilling, cementing, and perforating.

Using this technique, you often get natural well completions in zones that heretofore required extensive stimulation to overcome the damage.

Basically, the technique is perforating with deep penetrating shaped charges and immediately backsurging with maximum differential pressure to the wellbore. This often is done with the tubing practically dry, thereby fully utilizing the natural formation pressure to give clean, efficient flow charnels after perforating.

Results to date indicate you get more clean, producing perforations than with any other system.

The paper discusses the mechanical equipment that has been designed and field proved for running the guns on tubing below retrievable packers. Various hookups are shown for single, dual, or commingled completions.

Depth-control techniques for correct gun positioning are explained.

Field results of over 500 completions from Wyoming to the Gulf of Mexico are discussed, with emphasis on results completing fluid-sensitive formations.

Introduction

The increased demand for gas and oil in recent years has emphasized the need for increased initial well production and continued high production rates.

Intrastate gas demand at higher prices has created a tremendous opportunity for improved well completion engineering, especially in areas where the gas production was formerly unprofitable.

Therefore, a new approach has been developed and field proved on over 500 completions from Wyoming to the Gulf of Mexico.

Basically, formation damage of drilling, cementing, and perforating are overcome by perforating with deep penetrating shaped charges and immediately backsurging with maximum differential pressure to the wellbore. Thus, formation energy is utilized to give good, clean flow channels.

THROUGH-TUBING GUN APPROACH

Overcoming perforating damage with differential to the wellbore when shooting has been used for some time, especially with through-tubing type perforators rum on wire line. Fig. 1 illustrates this approach is not always a good solution to the problems of compaction and plugging.

In consolidated formations and/or fluid sensitive, shaley zones, the through-tubing guns may not give sufficient penetration to get beyond the invaded zone. Then, too, the small perforation hole size and the limited differential pressure used for wireline operation can result in having a lowered permeability zone and debris clogged perforation. Flow area then is greatly reduced.

Reduced flow area can result in excessive velocities that may cause water coning and/or sand flow.

WIRELINE CASING GUN APPROACH

Fig. 2 illustrates perforation with a casing gun and deep penetrating charges run in the conventional manner on wire line. The differential pressure is into the formation, and mud or a completion fluid is in the wellbore. The debris from the shaped charge, the cement, the formation displaced, and the well fluid often combine to form a crushed and compacted zone.
A Theoretical and Experimental Study of the Steady State Capillary End Effect
Authors: Hadley G.F. , Handy L.L.
Published: December 2007

Formulas are derived for calculating the steady state saturation profile and pressure profile resulting from the end effect. A numerical integration is required to obtain the results. Two dimensionless numbers containing various parameters of the system are introduced, which, along with the viscosity ratio and the fractional flow of one component, characterize the system. It is suggested that the magnitude of the end effect can be estimated just knowing these numbers. Sample calculations are carried out showing the influence of the various parameters on the end effect.

A discussion is given to show that in the measurement of relative permeability curves by the dynamic method, the end effect has a large influence on the preferentially nonwetting phase relative permeability curve if the pressure drop is measured in the wetting phase. If the pressure drop is measured in the nonwetting phase, the largest error appears in the wetting phase curve. If the pressures are measured in both phases, the errors tend to be self-correcting for each relative permeability curve.

End effects were measured experimentally on a Boise core for water-oil and gas-oil systems. Three different rates were used in each series. There was satisfactory agreement between the theory and experimental results.

Introduction

The so-called capillary end effect or the holdup of the preferentially wetting phase at the outlet of a porous medium during the simultaneous flow of two or more fluids has received considerable attention from time to time in the oil industry. In particular, there has been interest in how much influence the end effect has on the production from oil reservoirs and how much laboratory measurements of relative permeability are dependent on the end effect. Even though there has been quite a bit of qualitative discussion of these matters, there has been very little quantitative theoretical or laboratory work performed. The present investigation gives a fairly complete theoretical treatment of the capillary end effect within the bounds of Darcy's law and the capillary pressure relation. Experimental results on end effects are also presented for water-oil and gas-oil systems.

The end effect comes about at the efflux face of a core or around the wellbore in a reservoir because of the discontinuity in capillary pressure when the flowing fluids leave the porous medium and abruptly enter a region where there is no capillary pressure.
Transient Pressure Analysis of Bounded Communicating Reservoirs
Authors: Zhao Gang , Thompson Leslie G.
Published: December 2007

This paper presents a general methodology for computing semi-analytical transient pressure responses for bounded communicating reservoirs. It focuses on the hydraulic fluid contact relationship inside the complex geometry reservoir, i.e., the fluid flow between different parts of the reservoir, and reveals the transient pressure behaviors of different kinds of bounded communication reservoirs, such as parallel communicating channels and branching channels. It can also predict the transient pressure behaviors of channel and splay reservoirs and other complex reservoir shapes.

The method proposed consists of decomposing the original complex-geometry bounded reservoir into a set of simple-geometry reservoirs, which interact with each other by transfer of fluid and equality of pressure over the regions where they are in hydraulic contact. Analytical solutions are written down for each of the simple bounded reservoir components in terms of the unknown pressures and fluxes at their boundaries, and the coupled systems are solved for the desired wellbore pressure responses.

The source and sink method is used to compute the pressure response in the Laplace domain and the results are inverted numerically using the Stehfest Inversion algorithm. The proposed methodology can be extended to any system where the Laplace-space solution can be easily written in terms of integrals of real-space source/sink functions, including production at constant bottom-hole pressure, wellbore storage effects or naturally fractured systems. Minimizing the computational requirement is still a topic of research. Excellent pressure responses and their derivatives have been obtained for the bounded communicating reservoirs. Further research will be focused on the behaviors of other naturally-occurring complex geometry reservoirs formed through depositional and tectonic processes.
Viscoelasticity of ASP Solution is a More Important Factor of Enhancing Displacement Efficiency than Ultra-low Interfacial Tension in ASP Flooding
Authors: Hou Jirui , Liu Zhongchun , Xia Huifen
Published: December 2007

In Alkali-surfactant-polymer flooding, although the high concentration of alkali, for example 1.2%wtNaOH in ASP flooding in Daqing oilfield, can lead to an ultra low interfacial tension, it brings many new technological problems such as scale production in well bore, reduction of injectivity resulted from producing of alkali scale etc. The sharply shortened period of checking pump have adversely influenced the production of wells.

In this paper, the effect of alkali on viscoelasticity of displacing phase and the effect of viscoelasticities of ASP solution on displacement efficiency has been studied by studying rheology of ASP solution and physical simulating of ASP flooding which included the macro-displacement experiments in heterogeneous models and micro-displacement experiments to ASP flooding in Daqing oilfield. The mechanism that the viscoelasticity is more important than ultra low interfacial tension as a factor of affecting displacement efficiency has been confirmed. The sorts of surfactant, which can reach ultra low interfacial tension, are limited and expensive. These surfactants solution also need to add a high concentration of alkali to get ultra low interfacial tension. But for adding alkali, the viscoelasticity of ASP solution is decreased, and new technological problems have been brought about. On the contrary, decreasing the amount of alkali and weakening the demand of low interfacial tension can increase viscoelascity of ASP solution. The experimental results show that the displacement efficiencies of ASP solution with low alkali concentration aren't less than that with high alkali concentration and ultra low interfacial tension. The results not only enlarges the selectable range of surfactant and decreases the costs of ASP flooding, but also solves the problem of Alkali scale, and are of great importance to the further development of ASP flooding and its application.

In China, It is the first time to study the effects of ASP solution viscoelasticity on displacement efficiency by macro and micro physical simulation. Ultra low interfacial tension is not a necessary condition for enhancing oil recovery. The limit of capillary number theory has been discussed in ASP flooding. The mechanism of ASP flooding has been recognized again.
Screening Wells for Tight Gas From Single Point Flow Data
Authors: Cook David C.
Published: December 2007

On July 14, 2000 the Federal Energy Regulation Commission (FERC) issued a Final Order reinstating tax credits under Section 29 of the Internal Revenue Code (Section 29 tax credit) for wells producing from tight gas formations. In addition, some states such as Texas provide a severance tax credit for certain wells producing from tight gas formations. This paper provides a method to quickly screen for wells that may qualify for these tax credits using single-point flow test data.

In order to qualify for these tax credits a well must lie in an area that has been classified as a tight gas formation, that is an area where the available data suggests that the in-situ permeability is less than 0.1 md. This paper uses the same ONEPT technique Lee, Kuo, and Holditch presented in 1984 to estimate formation permeability from single-point flow data (SPE 12847) to screen wells for potential tight gas qualification.

This paper analyzes the sensitivity of the different variables involved in the Lee, Kuo, Holditch method of estimating permeability and develops a graphical screening tool to determine the likelihood that a well can be classified as a tight gas formation. Although, there are many variables involved in the Lee, Kuo, Holditch method, it is possible to screen wells graphically for tight gas using only four variables: the initial reservoir pressure, bottom hole flowing pressure, gas rate, and an estimate of reservoir thickness. This data is readily available from a typical single-point flow test and can be plotted to determine the likelihood that the well produces from a tight gas formation. Both unstimulated and fracture stimulated wells can be screened. The screening tool is verified by comparing it to known permeability data.