A demulsifier to be effective in breaking a water-in-oil emulsion has to possess higher polarity than that of the crude polarity than that of the crude oil natural surfactants. In spite of the polarity of those natural surfactants has never been measured, this general rule guided the use of chemicals in oil treatment along the years of the petroleum industry. Previous work developed a method to measure oil polarity, which proved that crude oils differ proved that crude oils differ widely in their polarities. Present work extends this method Present work extends this method to evaluate the polarity of several commercially available chemicals for crude oil demulsification. Because asphaltenes are considered to play a decisive role in emulsion stability , their polarity was also determined. The results provided an overall comprehension provided an overall comprehension about the polarities involved in crude oil demulsification.
Crude oil demulsification can be a costly operation in oil production, when the emulsions production, when the emulsions are stable and difficult to resolve. Therefore, a better understanding of the demulsification problems has always been searched for, when minimizing costs is desired.
Several parameters affect emulsion stability; among them the type and amount of crude oil. natural surfactants, which act as emulsifying agents, play an important role.
Crude oil natural surfactants migrate to the water-drop surface and diminish oil-water interfacial tension. All emulsifying petroleum constituents are polar petroleum constituents are polar compounds containing heteroatoms (N, S, O) in their molecules. The heteroatomic components of crude oils are generally designated as resins, which include organic acids and bases, and asphaltenes. Their presence confers polarity to crude oils, consequently, the oil affinity to water and the stability of emulsions increase.
In this work, a brief summary is presented on the fundamental principles of multirate testing. The main objective is the analysis of several field cases where the technique has been successfully. in the determination of drainage area reserves. The method of solution is presented for pressure transient analysis and involves pressure transient analysis and involves the use of a numerical simulator in most of the cases for an optimum reservoir modeling. Examples of tests conducted in the Maracaibo Lake fields are presented. Based on several field cases, an efficient design of the multirate test in order to get the reservoir evaluation objectives was obtained. An extended flow rate period was added to the conventional way to conduct these tests resulting in a better reservoir description for the drainage area investigated. The results were used to determine the next development well in the field under study.
It is very common to find the solutions for the transient wellbore pressure as predicted by a given reservoir model in predicted by a given reservoir model in the form of graphical displays also known as type curves. Typical solution shown is the wellbore flowing pressure for a well producing at a constant rate. From a producing at a constant rate. From a practical point of view, it is often practical point of view, it is often mentioned that to keep a constant flow rate is many times the exception and not the rule and build-up tests are more common than drawdown tests. According to the literature, type curves for drawdown test have been used to analyse buildup data. The assumptions and limitations have been also pointed out. With the advent of advanced testing production equipment that permits a controlled production during the test and also to high resolution pressure gauges it is possible to carry outs pressure gauges it is possible to carry outs pressure drawdown test with a high degree pressure drawdown test with a high degree of confidence for the obtained results. also and it is the case treated in this paper, drawdown tests in the form of paper, drawdown tests in the form of multirate test are preferred in cases where shutting in the well is not convenient due to differed production. It is the objective of this work to show that multirate tests can be successfully implemented from an operational point of view and that by adding an extended flow period, a complete evaluation for the well/reservoir system is obtained. IPR and dynamic reserves associated to the drainage area of the well are obtained results from multirate analysis.
The removal of drilling mud is a very important step for a successful primary cement job. Since cement is practically incompatible with drilling muds (a factor which causes gelation at the mud/cement interface and reduces displacement efficiency), spacer fluids are often used between the mud and cement; the proper selection of these fluids being a "must". A properly designed spacer fluid should maintain the drilling mud and cement slurry separated under the most severe conditions of the size of the hole to casing ratio; a spacer fluid has to be compatible with the drilling mud and the cement slurry to be used during cementing operations.
In response to these needs, a new Mud Removal Package - with a new group of spacers - has been Package - with a new group of spacers - has been introduced in Latin America since 1990. The fluids are mainly made of polymer blends, developed especially to be used with the Effective Laminar-Flow Technique and the Turbulent-Flow Technique. This article describes the two displacement techniques. It analyzes all the data obtained from compatibility tests with cements, muds and the new spacers. Two case histories are also included, as well as; a summary table containing data from field cementing jobs where these spacers have been used.
When the cement slurry is pumped into the well, it is necessary to fully remove the drilling mud from the wellbore where the cement is to be placed. Failure to displace all the mud can result in numerous problems such as channeling, cement contamination, poor bonding to casing and the formation, gas migration to the surface, leading to an unsuccessful cementing job. The designed cement slurry must be placed downhole to obtain a complete and impermeable fill of cement around the casing; especially a permanent isolation of the different permeable zones located around the shoe and opposite to fluid-bearing zones.
The use of a spacer ahead of the cement slurry on primary jobs has played an important role in primary jobs has played an important role in removing efficiently the drilling mud, thus improving the quality of the cement job. Moreover, spacers work as buffers to avoid contact between the cement slurry and the drilling mud and are pumped either in Turbulent or Effective Laminar pumped either in Turbulent or Effective Laminar flow.
A new package for mud removal has been introduced to offer an optimized removal of the mud fro the well. The package contains both a new family of spacers and a special computer program to help select the proper space, its program to help select the proper space, its volume and the most appropriate placement technique.
This paper reports ongoing work at Stanford University aiming at better understanding of steam-foam flow behavior with oil present. Steam foam systems were studied in a one dimensional sandpack at residual oil saturation (about 12%). The strength of the in-situ generated foam, indicated by pressure gradients, is significantly affected by injection procedure, slug size, steam quality and non condensible gas (nitrogen). In the range studied, surfactant concentration has a minor effect.
In the presence of residual oil, simultaneous injection of steam and surfactant fails to generate foam in the model, while the same procedure generates a strong foam without oil. When surfactant is injected as a liquid slug ahead of the steam, foam is generated, albeit at a lower strength than when no oil is present. The minimum slug size required to generate foam by present. The minimum slug size required to generate foam by this procedure is about 5% of the pore volume at 1.0% weight concentration. Above this minimum, increases in slug size or in concentration had little effect. The quality of the steam when it is increased, improves the foam strength. One implication of these results is that savings in the amount of surfactant needed for a steam-foam project may be possible by using a large slug of dilute solution. That is, if the slug volume is above some minimum, a dilute concentration may give acceptable foam generation. The reverse procedure, a small slug of high concentration surfactant gives poor foam generation and should probably be avoided in the field. Steam quality effects are consistent with the existing literature.
Foaming additives have been used extensivelly in the field to improve steam injection efficiency (Castanier and Brigham). The purpose of foaming additives is to reduce gravity override and channeling to injected gases and improve gas/oil ratios and sweep efficiency. Despite numerous studies dating back to the 1950s the mechanisms involved during the flow of steam/surfactant/noncondensible gases in an oil reservoir are not fully understood. Modelling of steam foam processes in order to predict production of oil is not yet possible. Optimization of the injection method, amount, concentration and type of surface active agent, relative amounts of steam and noncondensible gas, and steam quality is needed for better application of this enhanced oil recovery technique.
Previous studies have focussed on selecting thermally stable Previous studies have focussed on selecting thermally stable surfactants suitable for use as foaming agents at steam injection conditions. Most of this work was performed without oil or under static conditions. Recent work by Hamida et al. showed that at his experimental conditions it was not possible to generate foam as seen by increased pressure gradients when residual oil saturation to steamflood was present. The procedure that they used was coinjection of steam, nitrogen and procedure that they used was coinjection of steam, nitrogen and surfactant solution. Other authors (Demiral et al.) reported success with the slug injection method although at different conditions. This paper attempts to study steam foam mechanisms at residual oil saturation under dynamic conditions by using an alternating injection technique at the same experimental conditions previously reported by Hamida et al.
The equipment schematic is presented in Figure 1. The main components are injection and production equipment and a cylindrical tube of 2m length and 5cm diameter. The tube is instrumented with 21 thermocouples and divided in 4 sections for pressure gradient measurements.
In this work a testing technique based on analysis of the pressure transient created by formation surging is presented. The application of the technique is focused to cases where the tested well has high water cut besides strong bottom hole water drive and partial penetration. The analysis of the flow regimes shown under these conditions is presented. Several field cases are shown in order to see the application of this technique.
A major result derived from this study is that the technique can be successfully used in cases where by conventional pressure transient analysis no reservoir parameters can be obtained mainly because no radial flow is shown due to constant pressure effects. Linear, Radial, Bilinear and Spherical flow can be identified. Therefore making possible the calculation of transmissibility and skin effects.
A common testing technique used in some fields for active or producing wells where there is a strong bottom water drive is the surge test. The objectives are to check well condition regarding production in order to design a semi-submergible electric pump. When surging an underbalance condition is created that will help cleaning the perforations. To avoid water conning effects perforations are located at the top of the formation. Production is characterized by high water cut. Conventional pressure transient analysis under strong bottom pressure transient analysis under strong bottom hole water drive is difficult specially due to the very short flow period and quick flowing pressure stabilization. Under other conditions pressure stabilization. Under other conditions a common buildup test is characterized by a flow period previous the shut in. Usually shutin period is 2 to 3 times longer than production or flow period. The Horner method for data analysis in the buildup period based on the following equation
The conditions of applicability of the Horner method are well known. In particular the appearance of the semilog straight line where from the slope the reservoir parameters can be calculated is always subject to controversies. Test duration not long enough, wellbore storage effects just to mention a few are factors that may impose limits to the application of the conventional Horner method.
The Chicontepec formation, located in the State of Veracruz, Mexico has presented a high level of difficulty in presented a high level of difficulty in the stimulation process. The formation is a very clayey sandstone, sensitive to water. Because of this, fracturing with proppant should be done with a gelled proppant should be done with a gelled kerosene base fluid. This paper presents an appropriate fracturing design presents an appropriate fracturing design for this formation based on data obtained in the yield during more than 14 years of operations of this type. Also, extensive laboratory tests made on representative cores supported with computer simulations give backup to field observations.
The purpose of this paper is to determine an effective technique and materials for obtaining better hydraulically fracturing results in the Chicontepec Formation in Mexico.
Hydraulic fracturing treatments are employed to increase production. This involves pumping a slurry of viscous fluid and propping agent into the well with necessary pressure to create a fracture in the producing formation. The objective of most fracturing treatments is to obtain the highest production rates after the treatment.
Two topics of optimization can be considered in the fracture treatment: economic optimization based in the production recovery of the well and production recovery of the well and refinement of treatment procedures and pumping schedules to place the optimal pumping schedules to place the optimal treatment into the well at minimum cost. The first step is a gross economical optimization leading to the selection of the best treatment size; the second is a refinement of the job procedure to place the job at the lowest possible cost.
This paper presents the results of the study of the settling rate performed on C-P, C-L Proppants, and Sand for 16 and 20 mesh sizes.
The method of experimentation was Stoke's Method which is used for analysis; the Stoke's Law was not applied to the measurements. This is due to the fact that the Stoke's Law applies only to measurements of in newtonian fluids. The polymer (non-Newtonian fluid) used XCD is a shear thinning fluid with gel behavior and its viscosity is depended upon the fluid motion.
The test performed in a settling tube simulates static fluid condition. The results showed the effects of proppant density, diameter and size of particles, as described by Stoke's Law. The proppant C-P has 2.2 to 2.5 times the velocity of the proppant C-L. Proppants of size 16 mesh proppant C-L. Proppants of size 16 mesh have 3.2 to 3.6 times the velocity of 20 mesh proppants. The first shows the effect of the density and the second illustrates the size or diameter effects, respectively.
Particle-size determination can be studied Particle-size determination can be studied by observing the settling behavior of particles. A single sphere in a fluid of particles. A single sphere in a fluid of infinite extent settling under gravity is a good example to consider. A great deal of research has been undertaken to determine the relationship between settling velocity and particle size. A unique relationship between draft factor and Reynold number has been found, and this relationship reduces to a simple equation, the Stoke's equation, which applies to low Reynolds number relating settling velocity and particle size.
When a small body is allowed to fall freely in a viscous field, it soon reaches a velocity where the downward acceleration is balanced by the friction. Therefore, the velocity ceases to increase. This limiting velocity is expressed by the equation known as Stoke's Law:
where V is the particle velocity, D is the diameter of the particle, p is the particle density, po is the density of the suspending fluid, G is the acceleration due to gravity and is the fluid viscosity.
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.
In this paper we present novel solutions to the inverse problem as applied to low frequency electrical analysis of problem as applied to low frequency electrical analysis of cores for the visualization of displacement fronts. F r om electromagnetic theory, we first derive a low frequency equivalent circuit for each volume element of the core. The model consists of parallel combinations of frequency independent resistances and capacitances whose value we obtain in terms of the electrical conductivity and permittivity of the core material with and without displacing fluid. We then describe two algorithms for the determination of the admittance matrix which represents the core, starting from the voltages measured at external core terminals, when the core is excited by low frequency currents applied at such external terminals. The first derived algorithm is based on what we define as circuital iteration starting from the edges of the core . The second algorithm is based on the iterated solution of Poisson's equation in the interior of the core (for the complex case which considers conductivity and permittivity). We determine the errors obtained in the solution of different discretized cores by comparing the iterated solutions with the values given by the solution of the direct (or forward) problem.
The method of electrical imaging has been presented several times in the technical literature, and suggested as valid technique for the analysis of core samples since 1981. However the published information has been mainly concerned with the determination of the electrical conductivity image of the sample.
Little attention has been given to the proper circuital modeling of each volume element of the sample and its surrounding space, and to the limits of validity in frequency of the equivalent circuits.
In the present work we are concerned both with the modeling of each element of volume of a core, as well as the derivation of the algorithms that will allow the solution of the inverse problem. We focus on the problem of visualizing the displacement front of a displacing fluid injected in the core as indicated in Figure 1, from voltage measurements carried out at external core contacts. The system is excited by sinusoidal currents with angular frequency w, which are applied (from current source generators) at the external contacts. The core volume without penetrating fluid is characterized by a conductivity and a permittivity , the permeated core is characterized by a conductivity and a permittivity , and the surrounding space (air in general), is characterized by a conductivity and a permittivity . The permeability of all volumes is assumed to be , the permeability of free space.
We must stress that this is a theoretical paper. We are not concerned yet with very important real problems that will be encountered in measurements: the noise associated to the measured voltages, the errors incurred in voltage measurements at the current injecting contacts, the making of ohmic contacts at the core surface, or the experimental design of an analog to digital converters that should be fast enough so as to acquire the data in times which are small compared with the time constants for fluid core displacements.