Problem In Oil Fields Research Articles

Improving productivity in the 21st century through technology.

The force of information technology (IT)-essentially a staggering combination of computers, networks and application software-is pervasive and growing daily. In the industrial sector, IT dismantles barriers and encourages the development of a global market. IT encourages us to look at how business is done and how it could be done better. IT grows new business. At its core, IT helps bring people together. IT cements the links between client and product developer or service provider, between designer and manufacturer, and between diverse parts of a global organization. It aids team-building everywhere, not just within an organization, but also with partners and clients. IT enables the virtual organization.Knowledge management is a prerequisite for the growth and prosperity of the E & P industry in the future-a commitment each of us should make to lead the industry forward. The synergy gained by merging knowledge and technology provides a basis for increased oilfield efficiency.A structured approach to reservoir optimization provides the vehicle, supported by knowledge management systems that offer best practices and multidisciplinary expertise to solve oilfield problems. These steps provide a path for achieving cost reduction and reserve recovery targets vital to the future growth and profitability of the E & P industry.

A stochastic model for drilling optimization

Drilling optimization problems in oilfields are usually formulated and solved by using deterministic mathematical models, in which uncertain (indeterminate) factors or random issues are not taken into consideration. However, it has been widely experienced that random factors (such as those from soil layers, drill bits, and surface equipment) greatly affect the drilling performance. This paper introduces a new stochastic model for describing such random effects. This model, when used to optimization design, is more practical and provides a better characterization for real oilfield situations as compared with other deterministic models, and has been demonstrated to be more efficient in solving real design problems of drilling optimizations.

The use of naturally occurring selectively isolated bacteria for inhibiting paraffin deposition

One of the most severe problems at any oil fields producing paraffinic oils is that of paraffin depositions. Romania which has a long experience in oil production is also faced with this problem in many oil fields. The microbial treatment, based on the activity of naturally occurring, selectively isolated bacteria, is already proved as an effective alternative to conventional methods to prevent and remove paraffin damage. Using such kind of bacterial products, exciting results for inhibiting paraffin depositions have been obtained. In this paper results concerning the naturally occurring bacteria selectively isolated from hydrocarbon polluted sites as well as from paraffinic oils, semi-solid and solid paraffin depositions are presented. After a laboratory screening, 15 bacterial strains (BS 1–15), three bacterial consortia (BC 1–3) and a Special Bacterial Consortium (SBC1) were selected. For the selection of bacterial consortia, the classical enrichment culture method has been used. The Special Bacterial Consortium resulted from a mixture of BS 1–15 and BC 1–3 following the steps of the classical enrichment culture method. The BS 1–15, BC 1–3 and SBC1 have been tested for their performances in producing biosurfactants and biosolvents as well as for hydrocarbon utilisation. The SBC1 has been tested for its ability in degradation of hydrocarbons contained in several types of paraffinic or non-paraffinic oils, and then for inhibiting paraffin deposition on a `flow equipment' using two types of paraffinic oils. The SBC1 has been also tested for degradation of hydrocarbons contained in semi-solid and solid paraffin depositions. The results obtained could support further applications to prevent and control paraffin depositions.

Modelling the Thermodynamic Behaviour of the Carbonate System: Application to the Prediction of Carbonate Scaling in Oil-field Brines

Carbonate scaling in the wellbore and near-wellbore region of hydrocarbon reservoirs is a major production problem in the North Sea oil fields. Carbonate scale formation mainly results from changes in physicalchemical properties of fluids (i.e. pH, pCO2, T and P) during production or from chemical incompatility between injected water and formation water. Scale can impair productivity dramatically, thereby increasing hydrocarbon production costs. Prediction remains notoriously difficult, mainly due to difficulties for modelling the thermodynamic behaviour of the carbonate system in high salinity solutions at high temperature and pressure (HS/HT/HP). The DebyeHfickel approach, used for fluids of ionic strength (IS) lower than 0.1 molal, is not applicable to most oil-field brines (typical IS between 0.5 and 5 molal). True activities of dissolved species, accounting for all specific interactions between ions, must be known. The most comprehensive model to calculate activities in brines is the specific ion interaction model of Pitzer. A Pitzer-based computer model, e.g. SCALESIM, is thus being developed as part of an on-going ECfunded project (Qc-Scale; contract JOF3-CT95-0009) for prediction of carbonate scale in oil production operations.

Fractal analysis of shear joint roughness

The key factors which contribute to wellbore instability problems in oil and gas fields can be grouped as non-changeable and changeable. Non-changeable factors include the in-situ stress regime, pore pressures and the mechanical and strength properties of the formation and its bedding planes. Changeable factors include wellbore trajectory and mud weight (drilling fluid). In this paper, the effects of both changeable and non-changeable factors that influence wellbore stability are presented and discussed. Guidelines for efficient wellbore stability analysis have been developed. These guidelines can be used to improve the management of wellbore instability to achieve higher drilling efficiency and lower drilling costs.

Guidelines for efficient wellbore stability analysis

The key factors which contribute to wellbore instability problems in oil and gas fields can be grouped as non-changeable and changeable. Non-changeable factors include the in-situ stress regime, pore pressures and the mechanical and strength properties of the formation and its bedding planes. Changeable factors include wellbore trajectory and mud weight (drilling fluid). In this paper, the effects of both changeable and non-changeable factors that influence wellbore stability are presented and discussed. Guidelines for efficient wellbore stability analysis have been developed. These guidelines can be used to improve the management of wellbore instability to achieve higher drilling efficiency and lower drilling costs.

Part 3: Sulphate and Carbonate Scale Prediction in North Sea Oil and Gas Fields

Abstract Water-borne scales of sulphate and carbonate are major production problem in North Sea oil fields. Scale formation results from two processes: reduction in mineral solubility in produced formation water due to drops in temperature and pressure during production, and chemical incompatibility between formation water and injected seawater. Temperature and pressure drops are chiefly responsible for carbonate scale precipitation. Chemical incompatibility between the reservoir formation water and the injected sea-water is the most common cause of sulphate scaling. Furthermore, the precipitation of one mineral scale may be aggravated or alleviated by competitive co-precipitation of other mineral(s) and specific ion effects. This chapter examines the susceptibility of North Sea formation waters to carbonate and sulphate scale precipitation. Seawater contains a few thousand milligrams per litre (c.2800 mg 1 -1 ) of sulphate anions (SO 2- 4 ), a small amount (c.420 mg 1 -1 ) of calcium ions (Ca 2+ ) and trace amounts of barium (Ba 2+ ) and strontium (Sr 2+ ) ions. In many offshore fields in the northern and central North Sea, the original formation water has trace SO 2- 4 but excessive Ba 2+ and Sr 2+ ions (up to 2000 - 3000 mg 1 -1 ) as well as Ca 2+ ions (up to tens of thousands mg l -1 ). In normal oil field conditions, these two types of brines are usually chemically stable when they are kept apart. However, as seawater is injected into the reservoir formation during a waterflooding process, it commingles with the formation water in various locations of both reservoir and production systems to deposit sulphate mineral scales of barite (BaS0 4 ), celestite (SrS0 4 )

Developments in elemental concentration logging and applications

It is noted that the past decade has seen a dramatic growth of gamma-ray spectroscopy logging as a tool for solving geophysical problems. Developments have provided absolute elemental concentrations for a larger set of elements, using elemental analysis (including tracers) for solving many specific oil-field problems and providing a basis, through geochemical research, for developing a wide range of applications of borehole elemental analyses, such as chemically described mineralogy. Physical properties have been related to the mineral structure of the formation rock, such as cation exchange capacity, grain density, permeability, and source rock evaluation. Some areas of further development, both in the techniques of elemental logging and in the applications of the data, are discussed. >

Integrated computer-aided basin modeling applied to analysis of hydrocarbon generation history in a Northern Italian oil field

The application of reaction kinetics to the analysis of hydrocarbon (HC) generation processes requires a detailed temperature history of potential source rocks in order to obtain optimum results. The necessary accuracy can be obtained by employing integrated computer-aided basin modeling techniques to simulate the depositional history, resulting in a continuous record of temperatures throughout the study area. The technique has been applied to the analysis of an on/off-structure HC generation problem in a Northern Italian oil field. The simulation of the geologic processes shows that low sedimentation rates and, more importantly, the high thermal conductivities of the carbonate rocks, resulted in low temperatures throughout most of the geologic history of the study area, which were followed by a sudden, rapid temperature increase in the off-structure area during the last 6.5 ma. The calculated temperature history enables an accurate determination of the HC generation history using a kinetic approach, which shows how HC generation is closely controlled by the sedimentation history and structural development and which also describes its relation to trap formation. It also shows why HCs are generated at very low vitrinite reflectance levels, i.e. peak oil generation at approximately 0.6% R o . Determination of the HC generation rate gives additional, critical information, as even source rocks located in apparently good potential zones at present, i.e. in the on-structure area, can be of minor importance for a trap due to slow generation rates and consequent low expulsion efficiencies.

Initiation of an In-Situ Combustion Project in a Thin Oil Column Underlain by Water

Summary An in-situ combustion project was initiated in the Caddo Pine Island field in a thin oil column underlain by a water zone. An inverted five-spot well pattern was selected for the project, and the formation was ignited in Sept. 1980 to evaluate the potential of enhanced oil recovery by a combustion process. This paper presents engineering and laboratory procedures used in evaluating the reservoir for in-situ combustion. The program used to monitor the project performance, including both surface and subsurface measurements, is discussed. The paper reviews the design and installation procedures for the project wells and surface facilities, and presents project results. Introduction An in-situ combustion project has been initiated in the Nacatoch sand underlying the Harrell Fee lease in the Caddo Pine Island field, approximately 30 miles (48.2 km) northwest of Shreveport, LA (Fig. 1). The Nacatoch formation is an Upper Cretaceous semiconsolidated, friable, fine-grained sandstone reservoir located approximately 1,000 ft (304.8 m) below ground surface [800 ft (243.84 m) subseal. The formation contains a thin [29-ft (8.83-m)] column of high-viscosity, low-API-gravity oil that is underlain by a thick [100-ft (30.48-m)] ‘water zone. Primary recovery from the reservoir was low because of the absence of reservoir energy and because of the unfavorable mobility ratio between the viscous crude and the underlying water. Reservoir fluids and matrix properties are presented in Table 1. A typical well log and a structure map of the Nacatoch sand in the project area are shown in Fig. 2. The inverted five-spot well pattern (Fig. 2) encompasses five acres (20.23×10 m) and is centrally located within the Harrell Fee tract. The project was initiated by injecting air in Well 6, which was ignited on Sept. 17, 1980. Since ignition, daily gas analysis from the four producing wells indicates that an efficient combustion front is in progress within the pattern. A reservoir simulator was utilized in selecting and evaluating the pattern size and configuration for the insitu combustion project. Inverted five-spot, seven-spot and nine-spot well patterns ranging in size from 3 to 10 acres (12.14×10-3 to 40.47×10-3 m2 were considered. A 5-acre (20.23×10-3m2) pattern was chosen to obtain results from the project at an early date. All five wells in the pattern were drilled through the Nacatoch sand, and the casing was cemented by using a special heat-resistant slurry. Conventional and sidewall cores were taken from all wells (1) to aid in reservoir definition, and (2) to provide core material for laboratory tests. Logs from all five wells indicated sand continuity throughout the project area. Well completions were designed to accommodate both dry and wet combustion. Laboratory studies consisted of dry and wet combustion tube runs performed on core material from injection Well 6. The optimal injection water/air ratio (WAR) for the project was determined from the laboratory tests. The production facility is designed to handle normal oilfield problems as well as difficult emulsions and sand production associated with in-situ combustion projects. Air injection is supplied by a compressor rated at MMcf/d (28.32×10(3) M3/d) and a second standby compressor that was used during the ignition phase of the project. Ignition of the reservoir was accomplished by a downhole gas burner in the injection well. Ignition was confirmed by a downhole thermocouple. A program was developed to monitor project performance and combustion zone efficiency. The program includes bottomhole temperature and pressure (BHT and BHP) surveys as well as chromatographic analysis of the produced gas. Generally, the project response has been satisfactory. Process Selection The Nacatoch sand was selected as a candidate for thermal recovery methods. The reservoir contains a thin column of high-viscosity oil underlain by water. JPT P. 2233^

Oilfield Scale---Can We Handle It?

This paper is an analysis of the present knowledge of the formation, removal, and prevention of scale. This examination of the state of the art is presented to indicate the limits of current knowledge of oilfield-scale problems and to instigate additional research into these problems. problems. Introduction This paper** deals with three distinctly different scalecontrol problems in oil and gas fields: prediction, removal, and inhibition. An attempt is made to analyze the state of the art and to show the narrow limits of our present knowledge. This attempt is undertaken to present knowledge. This attempt is undertaken to indicate these limits to operating people and to stimulate additional research. All the known prediction methods have many shortcomings. Hardly any predict the actual amount of scale formed under a given set of conditions. Instead, they determine scaling tendencies. We can say that the scaling tendency of barium sulfate (BaSO4) is the easiest to predict and calcium sulfate (CaSO4) is much harder to predict and calcium sulfate (CaSO4) is much harder to predict. Presently, we do not have a workable method for predict. Presently, we do not have a workable method for predicting calcium carbonate (CaCO3) scaling. predicting calcium carbonate (CaCO3) scaling. The removal of each type of scale is technically possible, though perhaps not very practical. CaCO3 scale is possible, though perhaps not very practical. CaCO3 scale is the easiest to remove. CaSO or gypsum, is much harder to attack, and BaSO4 is by far the hardest to handle. Scale inhibition is an art and is successful only in less seven: cases of scaling. We do not know of scale inhibitions that are very effective when the temperature is much higher than 350 deg. F, or when large amounts of scale per barrel of produced water are formed. The application of the inhibitors may also cause problems in the field. Some inhibitors may cause more problems than they solve: the formation of pseudoscales and extreme emulsion problems may be observed under certain conditions. problems may be observed under certain conditions. How Much of a Problem Is Scale? Anyone who is vaguely familiar with oilfield operations has heard about the scale problem. However. there seems to be confusion about the extent of the formation and wellbore damage caused by scale in oil fields. To some, scale is not much of a problem because one seldom has a chance to see or physically examine actual samples of these deposits. Many scale deposits are, of course. located outside the well within the oil-bearing formation, where they are invisible. On the other hand, despite these analytical difficulties, some people think that scale is one of the major enemies in our daily oil- and gas-field operations. I belong to the latter group, and I sincerely believe that there are few wells that do not suffer flow restrictions from scale deposits within the drainage radius inside the formation. within the wellbore, or in the surface equipment. If we try to estimate the loss of revenue caused by flow restrictions due to scale, we come up with astronomical figures. I have reason to believe that oil- and gas-field scale costs on the order of $ 1 billion/year in the U.S. alone. This sum should be considered a minimum. I also believe that the scale problem is increasing. As our oil and gas reserves are depleted, we must produce these hydrocarbons under increasingly severe production conditions. More water production will favor many of the scale-forming conditions. In addition, we "pull" harder on our wells as less oil is being produced, thus favoring again all the scaling conditions. This means that the revenue losses resulting from plugging by scale will consume an increasing portion of our income as we deplete our reservoirs. P. 1402

Application of the Complex Method for Constrained Optimization to Oilfield Problems

Abstract In the application of optimization techniques, considerable difficulty is often encountered in determining the most applicable or effective method for solving a particular problem. In an attempt to solve this dilemma, M. J. Box developed the Complex Method, which can be used in solving a broad spectrum of problems. The method is a multivariable, direct-search technique that is efficient and convenient in optimizing problems with nonlinear objective functions subject to inequality constraints on explicit or implicit variables. This method has been applied successfully to many problems in the chemical industry; however, the applicability of this method for solving oilfield problems apparently has not been recognized. In this paper, two oilfield problems, a push-pull steam stimulation process problems, a push-pull steam stimulation process and a well-drilling schedule, were optimized using the Complex Method. The results were compared with those obtained by other optimization techniques reported in the literature. For both problems, the Complex Method was as efficient as other methods and probably was more efficient in obtaining the global optimum, both in terms of the number of objective-function evaluations required and of computing time. The solution to the constrained push-pull steam stimulation process was obtained push-pull steam stimulation process was obtained in one-fourth the number of evaluations required with the Hooke and Jeeves search technique; the solution to the drilling problem with 48 variables was obtained in only 2,123 objective-function evaluations, or 29 seconds of computing time on an IBM 370/165. Through the solution of two problems, the Complex Method was demonstrated to be easily applied and effective in obtaining optimum solutions as compared with other methods. This method should be implemented easily in obtaining optimum solutions as compared with other methods. This method should be implemented easily in obtaining optimum solutions to other oilfield problems. Introduction In recent years, the application of optimization techniques to oilfield problems has become widespread because of the possibility of increased profits or reduced costs with implementation of such studies. Several types of oilfield problems have been optimized using a wide variety of optimization techniques. E. L. Dougherty conducted an extensive review of the major applications of optimization techniques to oilfield problems. in these studies, the authors used a variety problems. in these studies, the authors used a variety of optimization techniques because of the difficulty of selecting an effective method for a particular problem. The Complex Method is a general optimization technique that can be applied directly to a variety of nonlinear problems with inequality constraints. The method is a problems with inequality constraints. The method is a multivariable direct-search technique; thus, the application of this method is especially convenient when derivatives of the objective function are difficult to obtain. The broad applicability of the Complex Method has been demonstrated in the chemical industry by successfully optimizing problems ranging from absorber-strippers to nonisothermal polymerization reactors. The method is implemented easily and is efficient in obtaining the global optimum while imposing inequality constraints on explicit and implicit variables. The objective of this paper is to demonstrate the usefulness and effectiveness of the Complex Method in obtaining the optimum values for oilfield problems, as compared with other methods. Two oilfield problems that previously have been solved by other methods were optimized using the Complex Method. The sample problems were the following:the optimum cycle length and the amount of steam injected in successive cycles are determined for a push-pull steam stimulation process such that the cumulative discounted net income is maximized; andthe optimum set of rotary speeds and weights on a bit is determined such that the drilling cost per foot is minimized in a drilling operation. These problems were selected to illustrate the wide range of mathematical formulations for which the Complex Method is applicable. The variable weight-speed schedule was selected for optimization rather than the constant weight-speed schedule because of the complexity of the variable weight-speed problem. SPEJ p. 123

Wellbore Gyp-Scale Control

Gyp-scale deposition in producing wellbores is a recognized problem in many West Texas oil fields. The results of gyp-scale formation are usually reduced producing rates, premature well abandonment, and high operating expenses. An effective gyp removal and inhibition program is necessary for successful operation where gyp-scaling problems exist. Development of the gyp-control program presently in effect in the Means (San Andres) Unit began in 1969 when gyp was originally detected in the Grayburg-San Andres reservoir of the Means Field in Andrews County, Texas. Prior to that time, a great deal of progress had been made in the area of gyp-scale control in the Means (Queen) reservoir which overlies the Grayburg-San Andres. This paper presents a description of the Means (San Andres) Unit Gyp Scale Control Program and the results achieved with that program.

The Kinetics of Crystallization of Scale-Forming Minerals

Abstract Reviewed here is the kinetics of crystal growth of sparingly soluble minerals such as calcium carbonate, calcium sulfate, and barium sulfate, which frequently cause scaling problems in oil fields. For all three electrolytes, the crystal growth is surface controlled and follows a second-order rate law with an activation energy for the growth process of 10 to 20 kcal mol(-1). The growth of calcium sulfate seeded crystal above 100 degrees C demonstrates the importance of characterizing polymorphic transformation processes. Phosphonate scale inhibitors show differing modes of Phosphonate scale inhibitors show differing modes of imbibition in systems precipitating CaCO3 and CaSO4. Introduction The formation of crystals of scale-forming, sparingly soluble minerals continues to be a very serious problem for the petroleum engineer. Scaling arises from a specific set of geological, physical, and chemical conditions. Geological factors such as ground water circulation and mineral composition may mediate in scale formation as may physical factors such as pumping rate, well pressure, and the extent of fluid addition to the oil-bearing formation. However, the principal factors regulating scale formation in the oil field are chemical and such investigations can answer many of the problems. For example, scale caused by the addition problems. For example, scale caused by the addition of surface water to an oil-bearing formation can often be eliminated by chemical treatment of the injected water. A more important scaling arises from changes in subsurface mineral solubility due to variations in temperature and pressure under down-hole conditions. The difficulties are compounded by the fact that conditions frequently encountered under down-hole conditions, notably high pressure and high temperature, cannot be readily simulated in the laboratory. Sampling of an aqueous solution brought to the surface for analysis can lead to entirely misleading results owing not only to changes in temperature and pressure, but also to the fact that the solution may be actively depositing scale minerals within the well. In addition, the possible deposition of carbonate scale is dependent possible deposition of carbonate scale is dependent upon the carbon dioxide partial pressure in contact with the solution. The minerals that appear to pose the most serious problems in oilwell scaling are the sulfates of calcium and barium, and calcium carbonate. Calcium sulfate and calcium carbonate have solubility values that decrease with increasing temperature. The higher ambient temperature in the down-hole situation will therefore encourage the formation of scale deposits of these minerals. In the case of calcium sulfate the problem is complicated by the transition between the dehydrate, hemihydrate, and anhydrite phases. These calcium sulfate polymorphs may be stable or unstable under different conditions of temperature or of ionic strength. Barium sulfate presents a particularly serious problem, since it is very insoluble and cannot be dispersed once it has deposited as scale. Numerous studies have been made of the spontaneous precipitation of sparingly soluble minerals from solutions containing concentrations of the crystal lattice ions considerably in excess of the solubility values. Attempts are usually made to use controlled methods of mixing the reagent solutions containing the lattice ions, but it is extremely difficult to obtain reproducible results from such experiments. There are probably no systems that are entirely free from foreign substances or particles that can readily act as sites for the formation of nuclei of the precipitating phase. The attainment of so-called "homogeneous" phase. The attainment of so-called "homogeneous" nucleation conditions is therefore very difficult even when extreme precautions are taken to exclude impurities and foreign particles from the solutions. Experiments are frequently conducted to determine scaling thresholds in the laboratory by mixing solutions of salts containing the lattice ions and observing the appearance of the first precipitate. Such experiments are open to the same objections as those given above, however; moreover, they are frequently carried out in such a manner as to ignore important kinetic factors in the rate of precipitation. Thermodynamic interpretations of the results assume the attainment of equilibrium and involve the thermodynamic solubility products of the precipitating minerals. precipitating minerals. SPEJ P. 117

The Study on the Effect of Decrease of Pipe Diameter in Vertical Two Phase Flow

Calcium or paraffin deposition causes the decrease of tubig diameter. It is one of the problems in many oil fields that the increase of pressure drop is resulted from the decrease of tubing diameter. The effects of presence of smaller diameter section in a tubing string in two phase vertical flow were studied. The measurements were carried out at atmospheric pressure using air as gas and water as liquid. The vertical flow strings used in the experimental works were consisted of the about 5-m-long and 2.5-cm in diameter main section and the smaller dia meter section placed in the middle part of main section (shown in Fig. 1). The smaller size pipes were long between 2-cm and 50-cm and 0.52cm in diameter. From the results of the tests, the correlation was developed. The pressure drop in smaller size section is able to be calculated by using Eq. (5) and Eq. (6) with Fig. 7. The pressure drop is expressed in terms of the pipe length, liquid flow rate and gas liquid ratio.

An Improved Numerical Technique for Solving Multidimensional Miscible Displacement Equations

Abstract Difference analog equations of high-order accuracy describing stable miscible displacement are presented. The high-order-difference scheme eliminates almost all the numerical smearing, which is the result of the normally used approximations, and leaves only the effect of the physical dispersion in the solution. In a one-dimensional system, the technique involves an addition of a negative dispersion term to the continuity equation. The negative dispersion term, which is called the numerical dispersion coefficient, depends upon the flow velocity, the time-step size and the block size. The procedure is extended to multidimensional systems. As a check, comparisons of the computed results with analytical solutions in one- and two-dimensional systems are made. The error-function solution in a one-dimensional miscible system and a five-spot fractional flow curve computed from the potentiometric model are considered as the analytical potentiometric model are considered as the analytical solutions in the two cases. Based on the computed results, it has been concluded that the effect of the term with the negative numerical dispersion coefficient accounts for almost all the truncation error within the practical limits of oilfield problems. Introduction Miscible flooding is one of the most efficient hydrocarbon recovery processes known at the present time. Its application in the field, however, present time. Its application in the field, however, remains limited because of economic requirements. Recently, the development of vertical miscible floods has made the process economically attractive. The result is that many oil companies have proposed and started such floods in suitable reservoirs. The amount of solvent required to flood an entire reservoir miscibly can be roughly calculated by analytical methods. Since these methods are derived for a one-dimensional system, some important questions remain unanswered. Some of these questions are:How will the solvent bank develop under the proposed injection scheme?What will be the condition of the solvent bank at breakthrough? These questions can only be answered by two- or three-dimensional studies. Known numerical techniques simulating miscible displacement give considerable smearing of concentration in the liquid-liquid transition zone when applied to a Held case. The effect of numerical smearing in this case is significantly larger than the effect of physical dispersion. Therefore, in the past, immiscible simulators with controlled numerical past, immiscible simulators with controlled numerical smearing were used to simulate miscible floods. For example, in one case the two-phase saturation profile was displaced as near piston-like as possible, profile was displaced as near piston-like as possible, neglecting mixing due to molecular diffusion and convective dispersion. In another case, capillary pressure and relative permeability functions were pressure and relative permeability functions were modified to simulate the dispersion effect. It was stated that the second method is applicable to a system where numerical smearing is considerably less than the effect of physical dispersion. This limits the use of the second method to a system such as gas-gas displacement. In this article a high-order difference scheme for miscible equations is given. This scheme eliminates most of the numerical smearing, leaving only the effect of physical dispersion in the transition zone. The procedure is developed for one- and two-dimensional systems. Calculated results are compared with analytical solutions. It is shown that the procedure can be extended to a three-dimensional system. FORMULATION OF THE PROBLEM The differential equations governing a miscible displacement process for an incompressible system are the continuity equations and the flow equations. Numerical solutions of this set of equations have been described by Peaceman and Rachford and Warren et al. Their methods are adequate to simulate miscible displacement in laboratory systems. If one applies them to a field-size system, significant truncation errors are introduced in the results. Usually these errors are large compared with the effect of physical dispersion on the results. SPEJ P. 277

MODEL STUDIES OF SALT WATER INTRUSION1

ABSTRACTModel studies were and are still being used to verify certain theories in ground‐water flow systems in general. In complex cases, the model studies may be extremely useful especially when a theoretical rigorous analysis does not exist. The models cannot be considered entirely satisfactory due to the several drawbacks in each type in addition to the normal human errors in experimentation. This paper is concerned only with the viscous flow models. However, a brief summary of the other types of models, which may possibly be used in connection with salt water intrusion problems is given. It should be noted that some of such experiments are not directly related to the field of salt water intrusion. Two main types lie within this category: The gravity flow systems which are analogous to some phases of salt intrusion problems and problems in oil fields which bear general similarities to sea water intrusion zones. In oil fields, gas cycling studies give valuable information to sea water problems. Model studies are used by hydraulic engineers, geologists, petroleum engineers, physicists, foundation engineers and several other professional groups.

Prediction of Deposition of Calcium Sulfate Scale Under Down-Hole Conditions

The thermodynamic method of calculating calcium sulfate scale has been improved by including the effects of complicated down-hole phase equilibria. Although the modified method has its limitations, it appears to provide more reliable results. Introduction Calcium sulfate (CaSO4) scale, especially gypsum, still causes unpredictable problems in many oil fields. This type of scale can cause severe plugging of equipment and producing formations; it creates the necessity of costly workovers and stimulation jobs. The best method for combating this scale seems to be the application of inhibitors - for example, by squeeze techniques - before the scale is formed. The reason is obvious: it is much more economical to prevent the formation of scale than to repair the damage caused by it. To apply the most suitable inhibition method, we have to know if and to what extent scaling occurs. At least some knowledge about the likely location of scale within the wall is equally important. The present methods of predicting scale in an oil field do not give all the answers, even though the literature contains enough data to develop and prove a more precise and reliable method. It is still common practice to wait for a production decline in the field, then pull the tubing and find - more or less accidentally - scale on the now-exposed metal surface. This scale sample is considered a proof for the occurrence of scale. This procedure can be very costly, and irreparable damage can be done before the scale is detected. Besides, this method fails frequently because scaling can occur even without the deposition of scale in the tubing. A better method for scale prediction is the use of water analyses and solubility data of CaSO4 compounds in the oilfield brines. There are many publications1–9,12,13,15,16 on the solubility of calcium sulfate compounds in water and brines at 1 atm. Most of the data in these publications are in good agreement. Together with the information from the water analyses, they are used to predict potential scale deposition. Diagrams, empirical equations, or thermodynamic relations are used to find the "maximum" solubility of calcium sulfate, mostly gypsum, in a water of similar composition.6–9,12–14 If the Ca++ and SO4-- concentrations in the actual water approximate the calculated "maximum" concentration of CaSO4, the field brine is said to have a "scaling tendency". We believe that this method can give only vague and unreliable information because it gives the solubility of CaSO4 or its hydrates at 1 atm only.

Soft computing for qualitative and quantitative seismic object and reservoir property prediction. Part 1: Neural network applications

Fred Aminzadeh and Paul de Groot of dGB Earth Sciences begin a major series of three articles on the increasing use of soft computing techniques for E&P geoscience applications, focusing first on how neural networks can enhance seismic object detection. Soft computing has been used in many areas of petroleum exploration and development. With the recent publication of three books on the subject, it appears that soft computing is gaining popularity among geoscientists. In this paper we focus on one aspect of soft computing: neural networks, in qualitative and quantitative seismic object detection. In subsequent papers we will review other aspects of soft computing in exploration. Highlighted here will be the role neural networks play in combining different seismic attributes and effectively bringing together data with the interpreter’s knowledge to decrease exploration risk in four categories (geometry, reservoir, charge and seal). Three new books in the general area of soft computing applications in exploration and development, Wong et al (2002), Nikravesh et al (2003) and Sandham et al (2003) represent a comprehensive body of literature on recent applications of soft computing in exploration. Soft computing is comprised of neural networks, fuzzy logic, genetic computing, perception- based logic and recognition technology. Soft computing offers an excellent opportunity to address the following issues: ■ Integrating information from various sources with varying degrees of uncertainty ■ Establishing relationships between measurements and reservoir properties ■ Assigning risk factors or error bars to predictions. Deterministic model building and interpretation are increasingly replaced by stochastic and soft computing-based methods. The diversity of soft computing applications in oil field problems and the prevalence of their acceptance can be judged by the increasing interest among earth scientists and engineers. Given the broad scope of the topic, we will limit the discussion in this paper to neural network applications. In subsequent papers we will review other aspects of soft computing, such as fuzzy logic in exploration. Neural networks have been used extensively in the oil industry. Approximately 10 years after McCormack’s review (1991) of neural network applications in geophysics, much work has been done to bring such applications to the main stream of geophysical interpretation. Some of these efforts are documented in Wong et al (2002), Nikravesh et al (2003) and Sandham et al (2003) which include many papers and extensive references on neural network applications. Most of these applications have been in reservoir characterization, seismic object detection, creating pseudo logs, and log editing. In the next section, we will focus on two general areas of applications of neural networks. This will include qualitative methods with the main aim of examining seismic attributes to highlight certain seismic anomalies without having access to very much well information. In this case neural networks are primarily used for classification purposes. The second category involves quantitative methods where specific reservoir properties are quantified using both seismic data and well data, and neural networks serve as an integrator of the information.

Performance of Heavy Oil Dehydrators

Results from field tests of heavy oil dehydrators verify a general dependence on the fluid physical properties, on the charge rate, and on the electric field intensity, but reveal no apparent dependence on the water content or particle size distribution of the feed. Introduction Accompanying the crude oil produced from underground formations are often varying amounts of connate brine. It is generally necessary to separate ("dehydrate") the bulk of this water from the crude before it leaves the oil field in order to have a marketable product. The dehydration of production fluids has historically been a problem in conventional petroleum production operations. Recent use of thermal recovery production operations. Recent use of thermal recovery techniques has resulted in increased interest, partly from the belief that thermally produced emulsions are more refractory (and hence more expensive to resolve) and partly from the fact that production costs often represent a greater fraction of the crude oil selling price for thermal projects than for conventional production. The generally higher temperatures, production. The generally higher temperatures, increased driving forces, higher production rates, and addition of fresh water are often given as reasons for expecting emulsions from thermal production projects to be more refractory. There are occasional suggestions in the literature that dehydration of such emulsions can increase expenses. Because the annual expenditure in the Western Hemisphere for crude oil dehydration equipment presently exceeds $10 million, and that for treating presently exceeds $10 million, and that for treating chemicals ("demulsifiers") may double this amount, a better understanding of the fundamental processes governing crude oil dehydration can lead to appreciable cost reductions. It is the purpose of this paper to compare equipment design and operating criteria found in the literature with the results of field tests in order to evaluate the applicability of these relations to general oilfield practices. Emulsion Characteristics and Their Reported Effects on Process Design Emulsions encountered in petroleum production generally consist of two immiscible liquids with differing densities, one of which (the discrete phase) is finely enough dispersed within the other so that the rate of separation due to the density difference is unacceptably low. Most oilfield problems involve an emulsion in which an aqueous phase, containing both connate brine and any fresher water associated with the production process, is dispersed within the hydrocarbon production process, is dispersed within the hydrocarbon phase. phase. Emulsion Characteristics From a physical point of view, a crude oil emulsion can be characterized in terms of the properties of the two liquid phases and the state of dispersion of the aqueous phase within the crude oil. Traditionally, the interfacial film (third phase) that surrounds the individual droplets and is supposed to hinder their coalescense has been included in the characteristic properties of an emulsion; however, reliable properties of an emulsion; however, reliable characterization of such films and, more particularly, of their relation to dehydration problems, has proven elusive. JPT P. 1285