In this paper, a brief description is given to operational procedure involved in acquiring transient data using a down hole shut-in tool. Field cases (Maracaibo Lake are presented to show the advantages of this technique in active wells and for cases where reservoir pressure is below bubble point. A comparison is made between this technique and the one that is based on simultaneous measurements of transient flow rate and pressure. The benefits both from an economic point of view and from the reservoir evaluation side using this method are presented. A main result derived from this work is that the use of the down hole shut-in tool reduced the build-up time by a factor of 10 in some cases for tests conducted in Maracaibo Lake fields. A considerable saving in differed oil production was gained besides the benefits of having pressure transient data not strongly affected by wellbore storage and phase segregation which permits a better reservoir evaluation.
Reservoir description using pressure transient analysis is a well known and established methodology. Recent advances, both in reservoir models and equipment resolution for field well testing, show that successful reservoir evaluation results can be obtained if appropriate test equipment is used to reach the objectives. In the area of pressure transient data analysis, significant improvements have been reached, such as the use of the pressure derivative as a flow regime diagnostic tool and the regression both linear and non linear for the overall pressure profile analysis. Even though we are still faced with the inverse problem that is to say different models problem that is to say different models can match the same pressure transient data the use of the computer and the numerical simulation approach will definitely help in choosing the right reservoir model to match. In the area of testing equipment and pressure gauges with the advent of quartz type of gauges, a resolution as low as 0.01 psig can be easily obtained. This type of gauge is commonly used in may tests. Regarding equipment for testing, advances have been reached when testing exploratory wells (DST type of tests). Deeper formations and temperatures above 300 degrees F are tested every day and they pose a challenge regarding equipment performance.
An automatic history-matching algorithm has been developed to determine relative permeabilities and capillary pressure curves simultaneously frog the production history of a displacement test of oil and water through a core. Relative permeability and capillary pressure curves are represented by power functions. Those representations contain sole parameters which are found by minimizing an objective function. The objective function is ford by the sum of the square of the differences between experimentally measured and numerically simulated production data. The numerical simulator is an IMPES finite-difference program which models the one dimensional two-phase flow. The program which models the one dimensional two-phase flow. The analyzation is performed by a non-linear regression algorithm: the Quasi-Newton Approximation for the Least-Squares Problem Broyden- Fletcher-Goldfarb-Shanno formulae). The automatic history matching algorithm is applied to analyze the influence of capillary pressure on the determination of relative permeability curves. The algorithm is tested with simulated data and with actual experimental data. Database consisting of simulated experiments with random errors are tested to demonstrate the feasibility of the method. Besides, they provide exact relative permeability curves for comparison purposes. In effect, results obtained by using simulated data show the convergence and uniqueness of the algorithm. But the main observation is that relative permeabilities estimates can be in error when capillary pressure terms are neglected. Several sets of actual experimental data at inlet constant pressure are also tested. convergent solutions are always found. pressure are also tested. convergent solutions are always found. Three different objective functions are applied. They are formed by oil rates, total fluid rates or a combination of both. The solution is dependent on the chosen objective function. Best adjustments are found by applying a combination of oil and total fluid rates, and including capillary pressure.
Them measurement of relative permeabilities fall into two basic categories: the steady-state (Penn State) technique or the unsteady state (Welge) technique. The steady-state technique is the east direct, but it Is expensive and time-consuming. On the other hand, the unsteady-state experiment involves the displacement of oil by water through a sample of reservoir-rock initially saturated with oil and connate water. This technique is much quicker and less expensive than the steady-state procedure and in consequence is customarily performed - but the relative-permeability curves have to be inferred indirectly frog pressure drop and fluid production data measured during the test. In fact, these curves are calculated by matching the production data with results of a mathematical model of the two-phase flow. Traditionally, the matching is performed with, graphical methods based on the Buckley-Leverett model - i.e., JBN or JR methods. These procedures are not adequate for heterogeneous cores, or for low flow rate experiments in which capillary pressure terms cannot be disregarded. Furthermore they require the graphical or numerical differentiation of measured data, and this process of differentiation amplifies measurement errors. Automatic history matching techniques have been put forward to overcome these limitations. An automatic adjustment algorithm is composed of a numerical simulator of the unsteady one dimensional biphasic flow of oil and water through the core functional representation of the relative permeability curves in terms of a set of adjustable parameters; and a least squares criterion to minimize the differences between measured and calculated production history by varying the adjustable parameters. parameters. In those regression based techniques relative permeabilities have been estimated taking into account capillary pressure effects or neglecting them.
In-situ combustion is the most energy efficient of the thermal recovery methods. In light oil reservoirs, too little fuel may be deposited thus making combustion impossible while in heavy oil reservoirs too much fuel may be deposited thus ruining the economics of the process. A research program has been initiated to try to solve these problems. Water soluble metallic additives ere tested to attempt to modify the fuel deposition reactions.
In a previous paper, results were reported from kinetics experiments run on Huntington Beach, California and Hamaca, Venezuela crude oils in the presence of aqueous solutions of metallic salts. While the presence of copper, nickel and cadmium had little or no effect; iron, tin zinc and aluminium increased fuel laydown for Huntington Beach oil. The results were similar for the heavier Hamaca oil.
This paper describes thirteen combustion tube runs using four different crudes. In addition to the above two crude oils, a 12 degree API and a 34 degree API Californian oil were tested. The metallic additives iron, tin and zinc improved the combustion efficiency in all cases. Fluctuations in the produced gases were observed in all control runs but disappeared with the iron and tin additives. The front velocities were increased by the metallic additives. Changes were also observed in H/C ratio of the fuel heat of combustion, air requirements and density of the crude produced. The amount of fuel deposited varied between the produced. The amount of fuel deposited varied between the oils. For Huntington Beach oil, the amount of fuel increased in the order: zinc, control, tin and iron while for the Hamaca crude the order was: control, iron and tin. The most interesting result occured with the light California oil. The control run showed that we were unable to propagate a combustion front while with iron additive a good combustion was achieved.
To date we have not been able to find a suitable additive to reduce fuel deposition. Iron and tin salts seem suitable agents to increase fuel when that is needed.
In-situ combustion is after steam injection, the most widely used thermal recovery technique. In this process, air or oxygen is injected and burns part of the oil which is used to generate a burning front which propagates in the reservoir. Oil production is improved by the hot gases generated during the burn. production is improved by the hot gases generated during the burn. Although the main application of thermal recovery is to re-t cover viscous heavy oils, a broad range of oils and reservoirs are potential targets for these recovery methods. The major constraint limiting the applicability of in-situ combustion is the amount of fuel formed on the reservoir matrix ahead of the combustion zone. If insufficient fuel is deposited, as can be the case for light oils, the combustion front will not be self sustaining and will die from lack of fuel, Conversely, if excess fuel is laid down, the front advance will be slowed and the quantity of oxidizing gases required to sustain combustion will be uneconomical. The amount of fuel formed and the velocity of the combustion front are governed by the kinetics of oxidation and pyrolysis reactions of the crude oil in the porous matrix Catalytic compounds affect the kinetics of the reactions and so can influence the amount of fuel formed. If the proper catalyst can be introduced in the reservoir to modify the oil's tendency to deposit fuel, then in-situ combustion could be made feasible for a broader range of crude oils and reservoirs. Such an application was first presented in 1985 by Racz. Recent work at Stanford University (Shallcross et al. and Baena et al.) showed that water soluble metallic additives can change the kinetics of the combustion reactions.
The pipeline transportation of petroleum fluids can be significantly affected by flocculation, deposition, and plugging of asphaltene, paraffin/wax, and/or diamondoid in the transfer pipelines, tubulars, pumps, and other equipment. The economic implications of the problem of heavy organic depositions in such processes are tremendous.
In this report Mexico's experience with the pipeline plugging due to heavy organic deposition is reviewed and analysed based on the present state of knowledge. The modeling basis of a comprehensive estimation and prediction technique is presented. This technique is based on observed field and laboratory data, statistical mechanical theories, polydisperse polymer solution theory, continuous thermodynamics, electrokinetics and transport phenomena, colloidal solution theory, and the FRACTAL aggregation theory.
A number of problems could arise during the production of petroleum which would drastically increase the production costs. Among these, wax deposition due to a drop in temperature, and asphaltene deposition due to a variety of causes, in the production tubing strings are the prominent problems [l-4]. Therefore, it is of great importance to understand the behavior of heavy organics under various operating conditions. An ultimate goal is to predict whether organic deposition will take place, and to be able to avoid getting to the onset of organic deposition region.
Surveys of field experiences [5-7] indicate that asphaltene deposition problem is one of the major factors that increases the production cost. Thus, being able to prevent such deposition, costs could be lowered appreciably. Mexican oil production and its heavy organic deposition problem was selected for this study because of the availability of an abundance of field and laboratory data about it. Laboratory analysis performed on asphaltenes extracted from samples of the crude oils prone to asphaltene deposition, and from the heavy organic deposits revealed that "Mexican" asphaltenes are very similar (in elemental analysis) to asphaltenes extracted from other sources, as can be seen from Table 1.
The difference would reside in the asphaltene-particle structure and charge which in the case of Mexican crude oils is negative [6,7]. The molecular nature and structure of the asphaltene fraction of crude oils has been the subject of numerous investigations. There are still serious shortcomings in consistency between such studies because of the varied assumptions that have to be made in deriving the molecular formulae.
This paper presents a new system to improve safety and reliability of a gas treating plant. The geographic location of the plant, isolated on a hilltop in the subtropical jungle in the north of Argentina, increases the importance of this system. The entire system is handled by Programmable Logical Control, Programmable Logical Control, which takes its information from four different sources: Manual Shutdown, Gas Sensors, Ultraviolet/infrared Fire Detectors, and Data Acquisition System. It is a real time monitoring and control system. Input information is processed in the PLC and action is taken automatically in accordance with the results of the analysis. The system can take the following actions: Close the flowline valves from the wells, Open the vent valves, Cut off the energy supply, Stopping the gas and propane compressor, Turn on the propane compressor, Turn on the fire pumps, Shut down the furnaces, Activation of the alarms. The difference between this system and other systems in similar plants lies in its flexibility and speed which help to avoid unnecessary plant shutdowns. All the elements connected with the PLC are tested every two seconds. In the control house, there is a panel that can operate the system manually if there is a problem with the PLC. It also features a mimic with LED for each data source. The color of the LED indicates one of the following conditions: Normal operation, Caution, Changing condition, Alarm.
The main risks incurred the operation of a natural gas treating plant are gas leaks, combustible vapors, fire and explosions. The application of codes and laws regulations to the design, the construction and the operation of these plants minimizes these types of risks but they do not fully prevent the occurrence of insuperable events. On the one hand, risks are increased by human mistakes and by inadequate maintenance of materials, which results in corrosion.
Minimizing the cost of drilling a directional well is a major concern for the drilling engineer. This computerized system was developed in order to provide the drilling engineer with an advisory tool which recommends changes in the Bottom Hole Assemblies (BHA). This results in better accuracy and faster decision making; hence, considerable savings in time and money.
The system involves five integrated modules:
- Acknowledge base where all the expertise concerning the subject is stored.
- A database with information from the BHAs used in drilling of previous directional wells and their statistical behavior.
- A database with information from the theoretical behavior of BHAs commonly used in directional drilling.
- A database with information from directional surveys performed over the path of the bore hole.
- Computerized applications developed to calculate and plot the path of the bore hole.
This system was developed using an expert systems technology, including a knowledge base and a inference engine. The computerized applications for plotting and calculating the course were developed in a conventional way using BASIC and PASCAL. Databases were all developed in a relational model.
The use of tools that permit process optimization, reduce the time spent between operations, develop new techniques and provide information updated and precise, are of high priority in the Industry and are part of the priority in the Industry and are part of the strategic planning of many successful companies around the world.
Constant efforts are employed in incorporating new technologies in order to improve the processes, specially those including new processes, specially those including new computational applications, as well as those promoting the creative abilities of the promoting the creative abilities of the personnel. personnel. Among other innovative techniques, Expert Systems have drawn special attention. The most meaningful ambition is that these Intelligent Systems can keep the knowledge as part of the capital of the corporations.
How can we define Expert Systems?. This question-has generated great controversy, but scientific and engineering circles agreed that it can be an "AUTOMATIZED SYSTEM THAT USES ARTIFICIAL INTELLIGENCE, AND MIMICS THE RESPONSES OF A HUMAN EXPERT IN ONE SPECIFIC FIELD OF THE KNOWLEDGE, BEING CAPABLE OF SOLVING PROBLEMS IN THE ABSENCE OF THE HUMAN EXPERT".
An experimental simulation on the miscible displacement in fractured oil reservoir is presented. The theoretical and experimental presented. The theoretical and experimental studies are based on the ideas originally developed by Coats and Smith and recently modified by Perez-Cardenas in connection with miscible and immiscible displacements in heterogenous media which contain a double-porosity system. The proposed model considers that fluid displacement takes place through the fracture system by Convection-Dispersion process, while the matrix blocks exchange matter with the fractures mainly by hydrodynamic dispersion and molecular diffusion. To test the theory and experimental model, several displacements simulations were carried out with real field data. This paper describes application of two-dimensions simulations to miscible displacement during waterflooding operations. The first section describes a method of calculating the behavior of a water salinity tracer by use of an analytical solution for the Dispersion-Convection Equation. The second section of this work extends the analytical results in Berea sand cores. Finally, the last section covers the field simulation, thus the objective is to study the tracer evolution for frontal displacement simulation. Results are presented on calculations of salinity digital images for each evolution step at several pore volume injected and levels of mechanical dispersion-convection.
In Mexico several millions of additional reserves have been generated through waterflooding, one of the most important methods in improving recovery from oil reservoirs. Waterflooding as a secondary oil recovery is the most ancient method used in Mexico because it is economic and easy to introduce. Waterflooding begins by injecting treated water by means of several wells for the frontal displacement technique, per example an array of seven wells. In displacements in porous media a variety of instabilities in displacement front can arise that detract from efficiency of displacements of one fluid to another. Immiscible displacement at an unfavorable mobility ratio is not well known to be unstable to viscous fingering of the water saturation into the oil. At same time, miscible displacement at a favorable mobility ratio is known to be a stable to viscous fingering of the injection water salinity into the reservoir water salinity. There have been many attempts to characterize the last phenomenon through laboratory experiments and direct simulations, but for the second phenomenon this paper represents a new attempt to characterize a reservoir. In particular for waterflooding we consider that two types of displacements say exist at same time: an immiscible displacement (oil by water) and a miscible displacement (water in situ by injected water). For immiscible displacement competition between viscous and capillary forces has a dominant effect on finger behavior, while for miscible displacement (water in-situ by injection water) a gradient of concentrations has a dominat effect on the same finger behavior too. Thus, hydrodynamical dispersion and viscous fingering are important parameters in miscible and immiscible displacements.
Several of the processes used to reduce the environmental impact of drilling are counter-productive. They can increase drilling cost and often worse if the waste disposal problem rather than solving or relieving it. Two-stage centrifugation is probably the worst of these processes. The probably the worst of these processes. The trends toward total reliance on shale shakers for solids control, and the return of the liquid portion of hydroclone underflow to the system, in unweighted muds, are also very troublesome.
This paper reviews the importance of solids control and its relevance to waste management, discusses closed mud system and other methods of handling drilling fluid waste, and reviews the proper design, installation, and monitoring of the solids removal system.
The importance of solids control in oil well drilling has been clearly established by field and laboratory studies conducted over the past 35 years. Simply stated, drilling mud quality is the key to efficient drilling, and solids removal is the key to drilling mud quality. It is not coincidental that the companies with the most efficient drilling operations are those which devote the most attention to solids control.
With growing concern about protection of the environment, the use of closed mud systems has been. increasing. Some of the methods used to close these systems lead to reduced drilling fluid quality and -in the long run- to increased waste generation. Many important lessons about the relationships between solids control and drilling costs, learned since the introduction of hydroclones in the 50's, appear to have been forgotten. As a result, the use of counter-productive practices in the use of solids removal practices in the use of solids removal equipment is increasing. Three of these practices; double-centrifuging, the misuse practices; double-centrifuging, the misuse of "drying" shakers, and the removal of desanders and desilters alter improving shale shaker quality will be discussed in this paper.
THE IMPORTANCE OF SOLIDS CONTROL
The relationship between drilled solids and common drilling problems is clearly established. Excessive drilled solids concentration reduces filter cake quality, thereby increasing downhole filtration and cake thickness. This increases the likelihood of encountering unacceptable levels of torque and drag, stuck pipe, sloughing, and problems associated with increased surge and swab pressures. Also, and of much more importance, higher drilled solids contents significantly reduce rates of penetration, increasing drilling cost and the risk of wellbore instability caused by prolonged exposure of open hole intervals.
It has been proven that the adverse effects of drilled solids upon the drilling operation become more serious as the particle size decreases. Colloids, the finest solids, are the most damaging. Many of the solids generated by the bit enter the system as colloids, others become colloidal as they are circulated.
In waterflooding operations in fractured reservoirs, imbibition is an important mechanism for expelling oil from the rock matrix. Therefore, a detail knowledge of imbibition processes is necessary for improving oil recovery. Here a processes is necessary for improving oil recovery. Here a theoretical-experimental work concerning this subject is described. In the theoretical part of the work, an analytical model is developed. This model is based on the assumption that imbibition can be visualized as a diffusion phenomenon. Some experiments carried out with Berea phenomenon. Some experiments carried out with Berea sandstone samples validate the model.
Imbibition is an immiscible displacement process, whereby a fluid which is within a porous medium is spontaneously expelled by another fluid which surrounds the medium. In this case it is said that the outer fluid preferentially wets the solid. This phenomenon is caused preferentially wets the solid. This phenomenon is caused by the differential attraction forces between the pore walls and the fluids.
Imbibition processes are very important in waterflooding operations in fractured reservoirs. In these cases most of the recovered oil is expelled from the rock matrix by the spontaneous influx of water. In spite of its importance, only little fundamental research work has been done concerning imbibition mechanisms.
In 1958, Aronofsky and Masse proposed an empirical imbibition model for explaining oil recovery from fractured media. According to this model, oil recovery follows an exponential law. Later, Mattax and Kyte (2) presented experimental laboratory data that seem to agree presented experimental laboratory data that seem to agree with the Aronofsky and Masse model. Although this model give approximate results, it has the disadvantage of not explaining the mechanisms of water influx into the rock. Some additional interesting experimental information can be found on the papers of Graham and Richardson, Kleppe and Morse, Torsaeter and Silseth, Bourbiaux and Kalaydjian and Cuiec et al.
In this work a theory for imbibition processes is presented. The main point of the theory is the consideration presented. The main point of the theory is the consideration that the influx of the wetting fluid can be visualized as a diffusion phenomenon. Starting from this assumption, a mathematical formulation which describes water saturation as a function of time and distance is obtained. Also an expression for oil recovery as a function of time is presented. presented. For comparing the theoretical predictions with laboratory results, an imbibition run was carried out with a Berea sandstone sample originally saturated with oil and irreducible water. Experimental results are in good agreement with the model.
As mentioned before, imbibition processes have an important role in oil recovery during waterflooding, especially in fractured formations.
Horizontal drilling technology has become an economic reality, and the result has been a dramatic upsurge in the number of horizontal wells drilled. As the industry's experience of drilling, completing, and producing horizontal wells increases, so does the realization that horizontal technology is not always a solution to the problem of more cost-effective production. When evaluating the potential benefits of completing wells horizontally in a specific reservoir, the performance of the reservoir as well as the economics of drilling and completing the wells must be examined.
No matter why a horizontal well is drilled, the decision to drill must come from results that analyze all reservoir data available. Technical success and economic failures already associated with horizontal wells over the last three years have brought home this point.
GOALS FOR HORIZONTAL WELLS FROM A RESERVOIR PERSPECTIVE
The main goals of horizontal drilling are 1) maximize the ultimate recovery factor, 2) maximize the economics of recoverable reserves, and 3) sustain a high production rate for as long as possible to optimize ultimate possible to optimize ultimate recovery. The main objective from a reservoir management basis is the best exploitation of petroleum resources in the development and production phases. This includes the production phases. This includes the prevention of non-economic prevention of non-economic developments (waste or well interference) and the maintenance of a flexible response to production opportunities.
RESERVOIR DECISIONS TO DRILL HORIZONTALLY
The primary questions to ask are: 1) Why drill a horizontal well, and 2 What advantages does it offer? The majority of recent horizontal wells ere drilled because of expected productivity increases 2-20 times productivity increases 2-20 times higher over deviated or vertical wells. Generally, an improvement of about 2 to 2 1/2 times could provide sufficient economic justification for a well drilled horizontally.
The chief reservoir reason to drill horizontally is for production improvement by greater exposure to a producing zone or zones. A producing zone or zones. A horizontal well may also offer other advantages such as 1) pressure drops and fluid velocities are less around the wellbore, 2) water and/or gas coning is minimized, and 3) production usually is accelerated. production usually is accelerated. Increased production of horizontal wells can reduce the number of wells required for infill or development and reduce the number and size of platforms and/or other structures platforms and/or other structures required in development stages.