Abstract Oil recovery by miscible gas injection process has been a topic of research, development, and field testing for more than 40 years. There is still some disagreement in the interpretation of laboratory, field-test data and selection of predictive methods. Field experiments, however, have disclosed a number of problems with hydrocarbon miscible flooding that limit the oil recovery and diminish the economic attractiveness of these processes. Due to the fact that there is no generalized engineering method or model that adequately accounts for all the factors, each model tends to emphasize one or more aspects of the displacement while neglecting other aspects for the sake of tractability. A parametric study is done, using a 3-D, compositional numerical simulator "VIP" in order to design the model and analyze the results and performance of miscible gas injection in Hassi Berkine South field. A 9-component PR EOS was used to describe the phase behavior using IMPES formulation. The process of simulation study to design and optimize the full field model included the following steps: Start with a basic run, used as a reference case. 2) Compare the base case (miscible gas injection) with water injection process. 3) Consider the phase behavior effect. 4) The reservoir description effect. 5) Vertical sweep out. 6) Partial recovery of miscible flood. 7) Influence of grid variation. A cross sectional model was used to represent the simulation domain that covered about 5000 ft 2 in area and 100 ft in thickness. All the runs consisted of two wells, penetrating the entire layers, the injector in the first cell and the producer in the last one. From the results it has been concluded that the use of horizontal well data has compensated for lack of information about reservoir heterogeneity in lateral direction of the interwell locations. Introduction The term, "miscible fluid displacement", is defined as any oil-recovery displacement process, where there exists an absence of a phase boundary or interface between the displaced and the displacing fluids. Since there is no interface, consequently no IFT between the displacing fluid (i.e., the capillary number becomes infinite) and residual oil saturation can be reduced to it lowest possible value. Field testing and supporting laboratory research disclosed a number of problems with hydrocarbon miscible flooding that act to limit oil recovery and diminish the economic attractiveness of the process. For miscible displacement, to be a competitive process for a given reservoir, several conditions must be satisfied, because the incremental oil recovery is determined largely by reservoir properties and fluid characteristic (heterogeneity, fluids mobility, miscible sweepout, gravity stabilization, viscous fingering, etc.) Many researchers have worked on the reservoir engineering aspects of miscible flood design and performance. Important factors that need to be considered and carefully evaluated whether potentially take place. As yet, there is no generalized engineering method or model that adequately accounts for all factors which usually need to be considered. Each predictive method tends to emphasize one or more aspects of the miscible displacement, while neglecting other aspects for the sake of tractability. For this reason, a good understanding of basic miscible flood principles is required. Theory review For the discussion of predictive methods, we have to review some of the important factors that usually need to be evaluated in the design of the miscible flood performance.

Abstract This work presents procedures on how to apply a newly developed method to simultaneously determine the average reservoir pressure and initial fluid in place using surface production data and flowing bottom hole pressure. This new method is derived from a combination of a generalized material balance formulation and pseudo steady state theory. Reservoir simulation was used to generate production history and flowing bottom hole pressure via hydraulic tables, which were used to calculate average reservoir pressure and initial fluid in place in order to validate the accuracy of this new method. Five examples were investigated for production with vertical and horizontal wells in oil and gas reservoirs at constant rate or constant flowing bottom hole pressure. Calculated initial-fluid-in-place and average reservoir pressures agree very well with that derived from reservoir simulation. This new method is useful in analyzing surface production data in the following conditions: reservoirs significantly lack data, buildup tests are inconclusive in determining average pressure, buildup tests are expensive or difficult to run such as wells in tight and over-pressured reservoirs or with subsea completion. Introduction A frequently encountered difficulty in material balance calculation is lack of shut-in reservoir pressure. Without shut-in reservoir pressure, it is very difficult to perform material balance calculation. However, production data seems to be available most of the time. If we can make use of sand-face production rate and flowing bottom hole pressure, then it is possible to develop a new method which can be used to determine average reservoir pressure and initial fluid in place simultaneously. This new method does not require shutting-in of production, nor does it require a prior knowledge of drainage area, shape factor, and permeability under pseudo-steady state condition. Objectives The objectives of this study are to present procedures on how to simultaneously determine average reservoir pressure and initial fluid in place from production data and flowing bottom hole pressure for oil and gas reservoirs, and to test the validity of this new method with five examples employing vertical and horizontal wells. Mathematical Formulation This section gives a brief summary of a generalized material balance formulation of hydrocarbon fluid at reservoir condition. Detailed derivation of all the equations presented in this work can be found in reference and definitions of symbols are given in the nomenclature section. Oil Reservoirs (I) Material Balance Equations for Cumulative Fluid Production For oil reservoirs, the material balance equation with constant C f is represented by equation (1). Equation (1) (II) Material Balance of Oil Production Rate Assuming no water influx and negligible water production, the material balance equation of oil production rate at reservoir condition is represented by equation (2). Equation (2)

Abstract Darcy's law can not describe fluid flow accurately when the flow rate is high. In most cases in the recovery process, fluid flow is governed by Darcy's law. But when the flow rate is very high, for an instance, near the wellbore, Darcy's law is inadequate to describe fluid flow. In 1901, Forchheimer put forward a classical equation, known as the Forchheimer equation, to make up the deficiency encountered by Darcy's law at high flow rates. He added a non-Darcy term into the Darcy flow equation. The non-Darcy term is the multiplication of the non-Darcy coefficient, fluid density, and the second power of velocity. One of the most important aspects in determining the non-Darcy effect is to estimate the non-Darcy coefficient as accurately as possible. In this paper, theoretical and empirical correlations of the non-Darcy coefficient in one-phase and multi-phase cases in the literature are reviewed. Most researchers have agreed that the non-Darcy effect is not due to turbulence but to inertial effect. The non-Darcy coefficient in wells is usually determined by analysis of multi-rate pressure test results, but such data are not available in many cases. So, people have to use correlations obtained from the literature. This paper summarizes many correlations in the literature, and will provide a good reference for those who are interested in the investigation of the non-Darcy effect in the recovery process. Introduction In most cases (not near the well-bore) in recovery processes, the flow pattern is governed by Darcy's law, which describes a linear relationship between pressure gradient and velocity as follows, Equation (1) where u is superficial velocity, K is permeability, p is pressure, µ is viscosity, and x is dimension in x direction. Forchheimer 1 found that the pressure gradient required to maintain a certain flow rate through porous media was higher than that predicted by Darcy's law. He added a non-Darcy term to Darcy's law to account for this discrepancy, and the flow equation became Equation (2) where ? is fluid density, and ß is called the non-Darcy coefficient in this paper. From equation (2), we see that the non-Darcy term is a multiplication of the second power of velocity, fluid density, and ß. There have been many names for ß. ß was called: the turbulence factor by Cornell and Katz, 2 and Tek et al.; 3 the coefficient of inertial resistance by Geertsma, 4 and Al-Rumhy et al.; 5 the velocity coefficient by Firoozabadi; 6 the non-Darcy flow coefficient by Civan and Evans, 7 Liu et al., 8 Grigg and Hwang, 9 Narayanaswamy et al., 10 and Li et al.; 11 the Forchheimer coefficient by Ruth and Ma; 12 Inertial Coefficient by Ma and Ruth; 13 the beta factor by Milton-Taylor; 14 the non-Darcy coefficient by Thauvin and Mohanty, 15 Cooper et al., 16 and Li et al. 11 Equation (2) is called the Forchheimer equation by Ruth and Ma, 12 Milton-Taylor, 14 Ma and Ruth, 13 Civan and Evans, 17 Thauvin and Mohanty, 15 Coles and Hartman, 18 Cooper et al., 16 and Li et al. 11 When flow rate is very high, Darcy's law is not adequate to describe flow pattern. High-velocity gas flow occurs in the near-well-bore region and condensate reservoirs. Non-Darcy effect is important in these regions according to Kalaydljian et al. 19

Abstract The use of methanol in fracturing is not new technology. Its origin and application in hydraulic fracturing can be traced back to the 1960's. However, advances in fracturing fluid chemistry and breaker technology have improved dramatically creating new systems such as crosslinked methanol, the subject of this paper. Methanol has been utilized in the well stimulation industry for many years to take advantage of its low surface tension properties and miscibility with various formation fluids. This paper will discuss advances in crosslinked methanol system technology, system compatabilities, field application and practical safety precautions. The fluid system rheological properties and proper breaker application will be discussed as well. In recent years, the industry has become more aware of the challenges associated with formations recognized as "water sensitive". These issues can be associated with mobile and swelling clays, or undersaturation of the formation, otherwise known as aqueous phase trapping. The paper will discuss these issues as they pertain to proper fluid selection and more specifically, the selection of crosslinked methanol as a fracturing fluid. Formation properties of zones treated with crosslinked methanol will be presented as well as post fracture treatment results. Introduction Crosslinked anhydrous methanol is an excellent fracture fluid system comprised of approximately 96%-100% pure methanol developed to stimulate low permeability water sensitive formations. In the late 1960's, fracturing fluid systems incorporating carbon dioxide (CO 2 ) and methanol saw wide usage and some success in fracturing applications. These systems were used in an attempt to place proppant into a hydraulically induced fracture without the potential damage associated with water on "tight" formations displaying water sensitive tendencies. In the early 1970's, certain patents were awarded for a methanol fluid system termed "Vapor Frac," which consisted of transporting propping agents in gelled alcohol and CO 2 1 . This system was used for several years with varying degrees of success due to limited sand transport capabilities and poor fluid leak-off properties. In 1980, the first crosslinked methanol system was introduced to the industry. However, at this time the system incorporated 80% pure methanol and 20% water. While this system was compatible with CO 2 , it did not fully address the water sensitivity issue. By the late 1980's the first pure (96% methanol plus) methanol fluid system was developed and introduced to the industry, and saw wide use throughout Western Canada. In late 1992, additional opportunities to apply this technology presented themselves and research was undertaken to apply new fluid technology to crosslinked methanol. The system was introduced in Argentina; originally, to reduce treatment cost relative to CO 2 foam systems prevalent at that time. Since then, more than 200 jobs have been pumped 2 . The accumulated experience gained in Argentina further enhanced and expanded the original intended applications. In late 1998, depressed crude oil prices and a subsequent decline in drilling operations in the Permian Basin caused pumping service companies to seek applications for this improved crosslinked methanol fluid system in existing producing wells. The hope was to create a stimulation market in gas wells perceived as water sensitive, depleted or damaged to a point that conventional stimulation was not believed to be an option. It is in this application that crosslinked methanol has seen its greatest success in the Permian Basin.

Abstract We propose a simple and cost-effective approach to obtain permeability estimates in heterogeneous carbonate reservoirs using commonly available well logs. Our approach follows a two-step procedure. First, we classify the well log data into electrofacies types. This classification does not require any artificial subdivision of the data population but follows naturally based on the unique characteristics of well log measurements reflecting minerals and lithofacies within the logged interval. A combination of principal component analysis, model-based cluster analysis and discriminant analysis is used to identify and characterize electrofacies types. Second, we apply non-parametric regression techniques to predict permeability using well logs within each electrofacies. Our proposed method has been successfully applied to the North Robertson Unit (NRU) in Gaines county, west Texas. Previous attempts to derive permeability correlations at the NRU have included rock type identification using thin section and pore geometry analysis that can sometimes be expensive and time-consuming. The proposed approach resulted in improved permeability estimates leading to an enhanced reservoir characterization and can potentially benefit both daily operations and reservoir simulation efforts. The successful field application demonstrates that the electrofacies classification used in conjunction with sound geologic interpretation can significantly improve reservoir descriptions in complex carbonate reservoirs. Introduction Permeability estimates are a critical aspect of a reservoir description. In sandstone reservoirs, a linear relationship normally exists between porosity and the logarithm of permeability. Thus, permeability predictions in sandstones can be achieved with acceptable accuracy using porosity from well logs. In carbonates, however, petrophysical variations rooted in diagenesis, grain size variation, cementation, etc. can significantly alter the direct relationship between porosity and permeability. 1 Statistical regression has been proposed as a more versatile solution to the problem of permeability estimation. Conventional statistical regression has generally been done parametrically using multiple linear or nonlinear models. 2–4 Several limitations inhibit multiple regression techniques, many arising from the inexact nature of the relationship between petrophysical variables. Conventional parametric regression requires a priori assumptions regarding functional relationships between the independent and dependent variables. In complex carbonate reservoirs such underlying physical relationships are not known in advance, making traditional multiple regression techniques inadequate and often leading to biased estimates. 5–6 A variety of approaches have been proposed to partition well log responses into distinct classes in order to improve permeability predictions. The simplest approach utilizes flow zones or reservoir layering. 4,6 Other approaches have used lithofacies information identified from cores and also the concept of hydraulic flow units (HFU's). 7–11 However, in carbonate reservoirs such classification is complicated by the extreme petrophysical variations rooted in diagenesis and complex pore geometry even within a single zone or class. A major difficulty in this regard has been discrimination of classes from well logs in uncored wells. 12,13

Abstract This paper contains the results of laboratory and field tests where the corrosion system was carbon steel exposed to oilfield brines containing dissolved carbon dioxide and oxygen. Both uninhibited and inhibited systems were examined. The results are analyzed and placed in context with previously reported work dealing with related systems. Oilfields, in general, have less gas pressure as they mature. Ingress of oxygen into well annuli, into the vapor space in tanks, and through pump packing becomes more commonplace as a result. The corrosion consequences of this condition can now be quantified and corrective action can be taken to avoid equipment replacement and production losses. To the author's knowledge, no report of a systematic treatment of this subject exists in corrosion literature. Quantification of the effects, recognition of duration, and influence of corrosion inhibitor chemical types are among the novel contributions of this paper. Some of the significant conclusions from the work concern the magnitude and persistency of corrosion acceleration by oxygen in sweet fluids. At common oil well temperatures, acceleration was in the order of 10 to 30 mpy per part per million of oxygen. The concentration of oxygen was not reduced preferentially from these solutions but occurred at approximately the same rate as reduction of dissolved carbon dioxide (undissociated carbonic acid) concentration. Inhibition of corrosion in CO 2 /O 2 systems was more difficult that in CO 2 alone but could be accomplished. Introduction Although the problem of dissolved carbon dioxide corrosion has been widely studied, little information is available on the influence of oxygen entry into sweet corrosion systems. 1,2,3 Oxygen entry into sour (containing hydrogen sulfide) corrosion systems in the oilfield has received attention. 4 A paper is to be presented on oxygen entry into sweet systems at the National NACE Conference later this year. 5 The facets of oxygen entry into any oilfield corrosion system are solids production 6 , corrosion rate acceleration 7,8 , and increased complexity of corrosion inhibition 7,9 . This paper focuses on the consequences of oxygen entry into sweet systems in the laboratory and in an oilfield. A small amount of work was done in sour systems in the laboratory to relate the present study to previously reported results. Experimental Laboratory Laboratory tests were performed in 2000 ml glass resin kettles. Corrosion rates were monitored using recording linear polarization resistance instruments with 3-electrode probes. Tests were 24 hour exposures of AISI 1018 (UNS G10180) steel electrodes to stirred solutions at laboratory temperature. Wide-scan polarization curves were made at the end of same tests. Chemettes were used for determination of dissolved oxygen in both laboratory and field tests. In all-air and all-CO 2 tests, the brines (3% NaCl, 0.3% CaCl 2 •2H 2 O) were sparged for the duration of the test. In others, the brines were first CO 2 saturated, the sparging was stopped, a small port left open to the air for a predetermined period, then the kettle was sealed for the remainder of the test. Some kettles were completely filled with brine, but many maintained a gas headspace. Corrosion rates were occasionally determined by weight loss of the reference electrode. For sour tests, the brines were CO 2 saturated, 2 gm per liter of Na 2 S•9H 2 O was added, a port left open for a period, then the kettle sealed for the balance of the test. In these tests, oxygen equivalents were measured using cathodic polarization techniques described earlier. 6

Abstract Crude oils produced in many parts of the world contain asphaltenes. Asphaltenes plugging is a well-known cause of near-wellbore formation damage. The deposition phenomenon of asphaltene is mainly due to thermodynamic changes. Asphaltene deposition leads to production loss and requires expensive and in many times environmentally unfriendly corrective measures. This project proposes a novel technique for cleaning asphaltenes with laser energy. A laboratory laser diode modules was used to perform experiments. A two-inch column of bitumen/powdered limestone mixture was placed on top of a powdered limestone column in a flow cell, and the flow rates were measured before and after the laser treatment. The rate was correlated with permeability of this powdered limestone column in absence of bitumen. In a second series of experiments, actual consolidated limestone cores were subjected to flow of asphaltenic crude to simulate the damage process (i.e. permeability reduction). The damaged cores were subjected to laser treatments at various laser intensity and treatment time intervals. Experiment results indicated that asphaltene get disrupted after exposure to laser energy. However, the maximum amount of cleaning was noticed after an exposure of one hour and at a higher laser intensity. The increased flow rate measured employing the powdered limestone column after treatment can be used in an oil field to disrupt, or desegregate asphaltene from the vicinity of oil production wells. However, the simultaneous pumping is required during the laser treatment to avoid the reprecipitation of the disrupted asphaltene. The laser energy alters the thermodynamics of the system, which resulted in re-dissolve some of the asphaltene back into the liquid phase (reversible process). The proposed technique provides environmental friendly process and advanced technological breakthrough for treating asphaltene deposition in the petroleum industry. Introduction Many field cases and laboratory studies have reported precipitation and deposition of asphaltene during the recovery of oil. Asphaltene deposition generally appeared in the field first in surface facilities, especially in separators, during the oil final depressurization step (Garland 1 , Leontarities et al . 2 ). Another critical point along the production chain is within tubing in which precipitates form at depths corresponding to the bubble point pressure of produced oil (Brain 3 , Takhar 4 ). In some field cases, the reported asphaltene deposition in reservoirs has been so severe that reduced well productivity and injectivities (Stalkup 5 , Hotier and Robin 6 ).

Abstract One frequently encountered difficulty in material balance calculation is lack of shut-in reservoir pressure. This work presents a new method that can be applied under pseudo steady-state conditions to simultaneously determine the average reservoir pressure and initial fluid in place using only surface production data and flowing bottom hole pressure. This new method is derived from a combination of a generalized material balance formulation and pseudo steady state theory and is applicable to both oil and gas reservoirs for single-phase flow with no water influx. This method does not rely on pressure build-up tests, knowledge of drainage area or permeability, but it requires flowing bottom hole pressure. For constant flowing bottom-hole pressure or variable production rate, this work presents an algorithm to convert fluctuating or constant flowing bottom hole pressure into corrected flowing bottom-hole pressure with a decline rate essentially identical to that of average reservoir pressure. Methods for analyzing transient flow are also discussed in this work. This new method is useful in analyzing surface production data and flowing bottom hole pressures for reservoirs significantly lacking data. Introduction A frequently encountered difficulty in material balance calculation is lack of measured reservoir pressures, which are usually obtained from shut-in build-up tests. Without shut-in reservoir pressure, it is very difficult to perform material balance calculation. However, production data seems to be available most of the time. If we can make use of sand-face production rate and flowing bottom hole pressure, then it is possible to develop a new method which can be used to determine average reservoir pressure and initial fluid in place (IFIP) simultaneously. This new method is derived from a combination of generalized material balance method and pseudo-steady state theory to determine reservoir pressure and initial fluid-in-place simultaneously without relying on pressure build-up tests. Furthermore, this new method does not require shutting-in of production, nor does it require a prior knowledge of permeability, drainage area, and shape factor under pseudo-steady state condition. Objectives The objectives of this study are to present detailed mathematical derivation of a new method, which can be used to simultaneously determine average reservoir pressure and IFIP for oil and gas reservoirs without relying on pressure build-up tests and to provide solution algorithms of this new method. Mathematical Derivation The material balance of hydrocarbon fluid at reservoir condition states that the initial hydrocarbon pore volume is equal to the current hydrocarbon pore volume plus the hydrocarbon pore volume reduction due to pore volume reduction, expansion of initial water saturation, water influx, water injection, and water production. This concept is expressed in equation (1). Detailed derivation of equation (1) can be found in references (1, 2, 3, and 4). Definition of each symbol is given in nomenclature.

Abstract The displacement efficiency of a CO 2 flood has two components: microscopic and macroscopic displacement efficiency. This work focuses on the factors that affect microscopic displacement efficiency. The factors are pressure, temperature, oil composition, CO 2 purity, fluid properties, and reservoir pore configurations. These factors contribute to the phase behavior of a particular CO 2 flood. Mixing as a result of diffusion improves microscopic displacement efficiency as compared to mixing by dispersion, which decreases microscopic displacement efficiency. Phase behavior governs the development and sustenance of CO 2 miscibility with crude oil at reservoir conditions. Lower injection rates and higher residence time increases mass transfer between the oil and CO 2 . Improved transfer leads to oil swelling and viscosity and surface tension reduction that improve microscopic displacement efficiency. Uniform pore geometry and favorable pore structure causes higher microscopic displacement efficiency. The presence of dead-end pores decreases the displacement process. The volume and distribution of water within the pore affects the contact area between CO 2 and the crude oil and can impede the miscibility process. As possible, this work quantifies the affect some of the factors have on microscopic displacement efficiency and suggests means of improving the displacement process. Introduction Amongst the various enhanced oil recovery (EOR) processes, miscible CO 2 displacement mechanism is considered an ideal process as it enables the possibility of recovering the oil to zero residual oil saturation. Since CO 2 displaces the oil miscibly, the interfacial tension between the oil and CO 2 is eliminated. Consequently, all of the entrapped oil could be mobilized; and the realization of 100% oil recovery is possible. Oil recovery in a displacement process depends on the volume of the oil reservoir contacted by the injected fluid. Displacement efficiency ( E ) can be mathematically represented as: 1 Equation (1) The microscopic displacement efficiency ( E D ) relates to the displacement or mobilization of oil at the pore scale. It is a measure of the effectiveness of CO 2 miscible slugs to mobilize/displace the oil from pores in the rock where the miscible slug has contacted the oil. E D is measured by the initial oil saturation ( S oi ) and the residual oil saturation ( S or ) in the regions contacted by the displacing fluid. It can be represented by the equation: Equation (2) The macroscopic (or volumetric) displacement efficiency ( E V ) is a measure of the effectiveness of the displacing fluids in contacting the reservoir in a volumetric sense. Sweep efficiency and conformance factors are alternative terms used to convey the same concept. The macroscopic displacement efficiency is a measure of how effectively the displacing fluid contacts the volume of a reservoir both areally ( E A ) and vertically ( E I ). Mathematically, E V can be represented by the equation: Equation (3) E A is the areal sweep efficiency for a given portion of a reservoir or pattern. E A is defined as the area swept divided by the targeted, total reservoir area. E I is the vertical sweep efficiency, defined as the pore space invaded by the injected fluid divided by the pore space enclosed in all layers behind the location of the leading edge of the flood front. Reservoir heterogeneities, well patterns, and differences in the fluid properties of the displacing/displaced fluids govern the macroscopic displacement efficiency.

Abstract To prevent gas wells from load-up, it is necessary to study the cause of load-up and condition for liquids to accumulate in wellbore. The paper adopts the view that the liquids droplets entrained in gas wells tend to be flat shape and deduce new formulae for continuous removal liquid from gas wells. The results calculated from the formulae are smaller than that of conventional Turner's. However, the predicted results accord with practical situation of gas wells in China gas fields. In addition, for the easier application purpose, the paper put forward simple formulae from the deduced formulae under analyzing different factors affecting removal liquids from gas wells. The model explains why many gas wells produce without load-up when the producing rate is by far smaller than that of Turner's minimum producing rate. In order to help engineer working in gas fields judge load-up effluence on gas well production, the paper analyzes the production performance of load-up and near load-up as well as unloading gas wells through wellhead producing performance figures. Introduction Gas produced from reservoir will, in many cases, have liquid phase material with it, the presence of which can accumulate in the wellbore over time when transporting energy is low enough in the low pressure reservoir. The liquids accumulated in the wellbore will cause additional hydrostatic pressure on reservoir, which results in continued reduction of available transportation energy and affecting the production capacity. In some cases, it even causes gas wells to die. So it is essential to investigate the cause for gas-well load-up and to determine the minimum gas flow velocity and rate for gas wells to transport liquids to surface. Turner 1 compared two models, that is, the continuous film model and entrained drop movement model in 1969. He proved that liquid droplets entrained in the high velocity gas were more adequate for explaining gas-well load-up and used the model to investigate load-up of gas wells. Under supposing that the liquid droplets was spherical. Turner deduced the formulae used to calculate the minimum gas flow velocity and rate to remove liquid droplets with +20% adjustment. The minimum gas flow velocity and rate are known as the terminal velocity and critical rate. Turner also suggested that in most instances wellhead conditions controlled the onset of liquid load-up and the gas/liquid ratio in the range of 1370 to 178571 stdm 3 /m 3 did not influence the terminal velocity and critical rate. It is found that there are many gas wells producing rate much below the minimum flow rate calculated from Turner's critical rate formula and these wells still keep in good production state in China. To obtain the relatively accurate critical producing rate, the engineers in China gas fields adjust the Turner's critical rate with reduction by 2/3. Steve 2 found that the unadjusted liquid-droplet model tended to offer a better match of the field data according to two sources collected by him. The model still can not get suitable critical rate to explain the phenomenon of some gas wells which should be loaded up with his model but are not load-up in China natural gas fields. This paper presents formulae for predicting the terminal velocity and critical rate after analyzing liquid drop movement in high velocity gas stream. The calculated results with the present model are in conformity with the practical daily production record of gas wells. For the easier application purpose, the paper put forward simple formulae from the deduced formulae under analyzing different factors affecting removal liquids from gas wells. Steve 3 analyzed the behavior of load-up, near load-up and unload-up gas wells in wellbore. The paper shows the production performance of load-up ,near load-up and unloaded gas wells with wellhead producing rate figures through which engineers can have more understanding the effect of load-up on gas well production performance.

Abstract Numerous waterflooding projects are under way throughout the world for increased recovery. Water injection tests of oil zones are frequently undertaken during the planning phase of waterfloods. Analysis of the bottomhole pressure data recorded during these tests not only provides similar information to that obtained from production tests concerning the well and the reservoir characteristics but also allows the mobility ratio between the injected and resident fluids to be determined. Conventionally, pressure fall-off test data is analyzed using semilog plot of bottomhole pressure versus time. This paper is the extension of the Tiab's Direct Synthesis Technique 10–15 to pressure injection and Fall-off tests in water injection wells. Direct synthesis is a transient pressure analysis technique 10–15 , which uses log-log plot of pressure and pressure derivative vs. time. Thus, different straight line portions indicating different flow regions are directly analyzed. Direct synthesis is very useful in conditions of short and early time pressure data missing tests. It also verifies the results since it uses more than one equation for the estimation of reservoir parameters such as permeability, wellbore storage coefficient, and skin factor. Finally, field examples of pressure falloff analysis are presented to illustrate use the direct synthesis and results are compared with those from type curves and conventional semilog analysis. Introduction Traditionally water flood schemes have been implemented later in the life of the field following primary depletion. Now, such schemes are often considered during the initial development of a field. The economic viability of many fields depends upon successful implementation of water injection at early stage. Injection tests are, therefore, performed on appraisal wells drilled prior to the decision to develop the field. These tests are designed to assess both the efficiency of the filtration equipment and the injection characteristics of the formation. Operational and the cost considerations dictate that the maximum possible information be derived from these tests, which may be few hours of duration. Analysis of the pressure Falloff and injectivity tests has been discussed at considerable length in the literature. The pressure buildup during injection period, however, has received relatively little attention. The main reason is that falloff tests match to the pressure buildup test in production wells, which is easy to analyze. Furthermore, the injectivity test is mathematically difficult to handle due to moving boundary, the flood front.

Abstract A careful examination of the mud log and sidewall cores in certain interval of hydrocarbon anomaly, dry oil from low resistivity sands was surprisingly discoverded and confirmed afterward by well testing results. The problem with these sands is that the resistivity logs indicate high water saturation, but water free hydrocarbon will be produced. This paper discusses the different reasons sandstone reservoirs can have low resistivity. The mechanisms resposibles for low resistivity phenomenon are described as being caused by the inclusion of clay or pyrite minerals and as being due to microporosity. Clean bearing sandstone has high resistivity, but when this rock contains clay, or heavy minerals such as pyrite, the resistivity can become low. Pyrite shows a good electrical conductivity, that is usually comparable to or even higher than the conductivity of formation water, and can therefore have a larger effect than shale. In this work, different shaly sand models will be discussed and applied in two field examples to correct the calculated water saturation from shale effect to get the true water saturation level. The contribution of NMR log in solving problems of low resistivity microporisity sandstone reservoirs was iluustrated by a third field example. Introduction The reasons for low resistivity phenomenon are classified mainly into two groups. The first consists of reservoirs where the actual water saturation can be high, but water free hydrocarbons are produced. The mechanism responsible for the high water saturation is usually described as being caused by microporosity. The second group consists of reservoirs where the calculated water saturation is higher than the true water saturation. The mechanism responsible for the high water saturation is described as being caused by the presence of conductive minerals such as clay minerals and pyrite in a clean reservoir rock. The resistivity data must be corrected for the effect of these conductive minerals to reduce the calculated water saturation to the more reasonable levels associated with water free hydrocarbon production. High surface areas of certain inclusions e.g. clay minerals can cause high water saturation, although other mechanisms described as high capillarity can bind large amounts of water. In sandstones, high capillarity may be due to the existence of high to moderate surface clay minerals such as kaolinite or illite. In carbonates, high capillarity may be attributed to microporosity caused by recrstallization, dolomitization or oolites that creates seconday porosity. 1,2 Most formations logged for potential oil or gas production consist of rocks which without fluids would not conduct an electrical current. There are two types of rock conductivity: a) Electrolytic conductivity which is a property of for instance water containing dissolved salts and b) Electronic conductivity which is a property of solids such as Graphite and metal Sulfides such as Pyrite. Pyrite is a common heavy mineral associated with marine sedimentary rocks. It has a good electrical conductivity that is usually comparable to, or even higher than the conductivity of the formation water. The crystals of pyrite may form a continuous network even at low pyrite concentrations. Measured resistivity on dry pyrite ranges between 0.03 and 0.8 (m. Pyrite's conduction is of metallic (electronic) nature and consequently any transfer of current between water and pyrites is based on conversion from ionic to electronic conduction and vise versa. This lead to polarization at the water-pyrite interfaces with the corresponding frequency dependent electrical properties. Thus the electrical properties of porous rocks with pyrites are strongly dependent on the amount and distribution of pyrite and the frequency of the measuring the electrical current. The main problem with minerals such as pyrite is how to estimate their volume and the distribution from well logs. 3,4

Abstract Many oilfield service companies as well as oil producers have manually tracked assets over the years for a variety of reasons. The service companies have tracked assets such as pumps, packers, or other products to assist in R&D efforts. Being able to collect the data and compile statistics on run times and component failures enables the service companies to evolve and improve current products as well as design new products. From a producers perspective, compiling the same or similar data allows for the development of "best practices" in operating procedures and processes. Software products developed to address these needs have evolved with time to provide more functionality. However, many systems implemented to handle the total process of data acquisition, warehousing, querying, and reporting to achieve improved operating results have become more difficult and expensive to support than the value added. The value of the information has not diminished, but increased due to the fluctuations in oil prices and the continuing efforts to reduce lifting costs through design and process enhancements. The recent development of a web based tracking system incorporates workover management, downhole equipment, and chemical usage while enabling the operator and service provider the ability to easily enter and access the data. The system reduces the problems of database synchronization, multiple entries of the same data, and provides a common means through the Internet to interface with the information. The system links the operator in the field, the service company providing equipment or chemicals, and the district office together through a common database that each has access to. The system allows a technician in a pump shop, workover foreman in the field, or chemical sales person to easily enter data into the system using a laptop computer or touch screen technology. The data is brought back to the service provider's local office and is accessible to the operator through the Internet. Wells, well equipment, and equipment components can be tracked for run life and root cause of failure. The operation becomes an information network that uses the same data to accomplish different tasks but with a common objective of reduced costs and improved profitability. Introduction Service Providers. In the oilfield service sector, the larger service companies began internally tracking their own equipment failures many years ago. Until recently, the service industry's perspective on failure analysis has been much different than that of the producer. By evaluating and categorizing failures, new products can be designed to fill niches or actions can be taken to improve the product over the competition. If a service provider did not have a process improvement cycle in place or a way to continuously improve the current line of products offered, they could fail both competitively and financially. Over the years, manual tracking and reporting systems were put in place that involved the field service technician, equipment maintenance personnel at the warehouse, warehouse clerk, and local technical engineer or manager (Figure 1). Because of all the "handling" of data from the time a failure occurs until the root cause is determined, the probability of incorrect data resulting from human error becomes extremely high. Each person in the process could potentially enter bad or erroneous data into the system, thereby nullifying or reducing the value in the desired result. In addition, the lag time between the failure occurrence and the reporting cycle producing client reports is generally a month or more. If mistakes are made during this process and are discovered in the reports a month later, some data may be lost forever. Only by acquiring large amounts of data, and having a conscientious attention to detail by all persons involved in the process, can the statistical probability for correct interpretation of the data become more accurate.

Abstract The Minagish Oolite is a thick undersaturated carbonate oil reservoir in the Minagish field in West Kuwait ( Fig. 1 ) containing several billion STB. It is a mature but relatively undeveloped reservoir. Since discovery in 1959, it has produced 10% of its OOIP under a combination of natural depletion, gas re-injection and aquifer drive. Initial reservoir pressure had declined by about 450 psi prior to the Gulf war in 1990. The well blowouts following the war caused a significant pressure drop of another 700 psi. Following the blowout, plans were made to redevelop the West Kuwait fields and increase the production rate starting in 2001 and to sustain the plateau for at least 5 years. This strategy called for three-fold increase in the production rate of Minagish Oolite reservoir. Since the existing well inventory and the loss of the gas re-injection facility could not sustain the desired plateau rate, additional field development was required. To achieve the production target, a multidisciplinary team was formed to evaluate options. The recommended plan required the drilling of additional producers and installing a field-wide peripheral waterflood. The reservoir, however, presented a number of significant challenges to waterflooding, such as the presence of a substantial and not well defined tarmat near the oil/water contact, and uncertainties of lateral and vertical heterogeneities. In 1997 a full-field simulation model was developed, but this model didn't capture the water movement properly because of insufficient reservoir data at that time. As new core was obtained, a refined reservoir description was developed. Building on lessons learned from the previous full-field model and sector models, a new full-field model was developed which significantly improved well-by-well history matches. Although containing twice as many grid cells, the new model ran up to four times faster than the previous model by making use of the Analytical Aquifer option within the model, improved relative permeability curves and other model refinements. This paper traces the history of the field and the systematic evolution of the development plan. The reservoir simulation efforts including modeling strategy, history matching events, prediction runs, future direction and challenges are also addressed. Introduction Numerical simulators are an important tool for reservoir management, providing management the ability to observe how alternate development plans and operating strategies will affect future oil production and recovery. As additional information is acquired and new technologies are developed, it is necessary to periodically update the reservoir simulation tools. This report identifies the reasons for building a new model, the differences between it and the previous model, and documents the data-sources, files and the methodology used to construct the new model. The previous model ( FFM 97 ) was constructed and initialized in 1997. The model was based on a course 12-layer reservoir description and history matched reservoir performance up through the start of dumpflood water injection. In predictive mode, however, the model did not adequately predict the rapid water movement in the northeast quarter of the field or the arrival of initial water in the peripheral producers. Sector models constructed at the same time indicated that a refined reservoir description that incorporated the observed barriers and high permeability streaks should provide an improved match of the observed water movement.

Abstract Hydraulic fracturing has generally been limited to relatively low-permeability reservoirs. In recent years, the use of hydraulic fracturing has expanded significantly to high permeability reservoirs. The objectives of fracturing low permeability reservoirs and high permeability reservoirs are different and defined by reservoir parameters. The estimation of reservoir permeability, a variable of great importance in hydraulic fracturing design is frequently unknown because candidate wells either do not flow or a pretreatment pressure transient test is required. Consequently, Nolte has introduced a new method for adding after-closure fracturing analysis to the pretreatment calibration testing sequence that defines fracture geometry and fluid loss characteristics. The exhibition of the radial flow is ensured by conducting a specialized calibration test called mini-fall test. The derivations by Nolte, based on the theory of impulse test and principle of superposition, allow the identification of radial flow and thus the determination of reservoir transmissibility and reservoir pressure. This study presents a review of the after-closure radial flow analysis. A modified method is proposed to complete the Nolte's method for the determination of the reservoir transmissibility and reservoir pressure based on the pressure derivative. The application of the modified method is demonstrated on actual field data from calibration tests performed on several oil and gas wells. The reservoir parameters determined with this method are verified by comparison with results obtained from buildup tests. Introduction Hydraulic fracturing has been recognized to be an effective means for enhancing well productivity and recoverable reserves, especially for low permeability reservoirs, by reducing the resistance to flow area between the wellbore and formation. The appropriate fracturing treatment for a given well has been hard to design because of the numerous variables involved. The use of inaccurate reservoir variables to design treatments may lead to poor production estimates. In wells that are to be hydraulically fractured, minifracture treatment, called also calibration test, frequently is performed to determine parameters needed for the stimulation design. It is generally performed without proppant and therefore, retains negligible conductivity when it closes. Fracture pressure analysis was pioneered by Nolte 1,2 . The basic principles are analogous to those for pressure analysis of transient fluid in the reservoir. Both provide a means to interpret complex phenomena occurring underground by analyzing the pressure response resulting from fluid movement in rock formation. The analysis of fracturing pressure, during injection, during closing and after closure period, provide powerful tools for understanding and improving the fracture process. Advances in minifracture analysis techniques have provided methods for determination of fracturing treatment design parameters such as leak-off, fracture dimensions, fluid efficiency, closure pressure and reservoir parameters. These parameters can then be used to determine the pad volume required, best fluid loss additives to be used, and most importantly, to achieve the optimum fracturing treatment design. Fig. 1 shows a typical history of the calibration test from the beginning of pumping until the reservoir disturbance from the fracture decays back to the initial reservoir pressure. Fracturing pressures during each stage of fracture evolution (i.e. growth, closing and after-closure) provide complementary information pertinent to the fracture design process. Therefore, Fracturing pressure analysis may be reduced to three distinct types of analysis.

Abstract This paper presents a new production method in which the reservoir energy spent to lift the production from perforation-depth to the dynamic liquid level is replaced by surface energy, and consequently the well daily rate and cumulative production is increased by 200 - 250 %. The method can be used in any well at any time. The paper is based on the analysis of how the reservoir energy generated by the expansion of the reservoir fluids is used to produce the well: PROFITABLE USAGE: Moves the production through the pay zone into the well bore WASTEFUL USAGE: Sends the reservoir energy to: Overcome the liquid friction along the productionflow path. Lift the production from perforation-depth to thedynamic liquid level. Present production practice recognizes and reduces only the reservoir energy wasted to overcome the liquid friction through the pay zone by using better and cleaner perforations, acidizing, fracturing, and other techniques. When less reservoir energy is used to overcome the frictions through the pay zone, the well performance, in both rate and cumulative production, is increased. To date all artificial lifting methods are spending surface energy only to lift the production from the dynamic liquid level to the surface. However, the energy needed to lift the production from perforation-depth to the dynamic liquid level, the largest waste of reservoir energy, is now overlooked and has not been recognized as the most important way to significantly increase well performance. The proposed new production method substitutes the reservoir energy by surface energy in order to lift the production from perforation-depth to the dynamic liquid level. Accordingly the well performance in day rate and cumulative production is increased by 200 - 250 % compared to the actual well performance. The quickest and easiest way to produce the well according to the new production method, is to run a subsurface compensated plunger pump assembled from the API Spec-11AX parts, and work with the same beam pump. A subsurface compensated pump, is a liquid lifting device, which can not be drawn by the well pressure.

Abstract Crystal modifier chemistry is fast becoming very important in the enhanced production capacity of crude oil fluids. These products have been used for many years in offshore and refinery applications with a high degree of success. However, the broad usage of these chemicals in production areas has been spotty at best and often underutilized. Because of the incentive of increased fluid production resulting from crystal modifier application, producers have been more receptive to the usage of these types of treatment chemical applications. Considering this increased willingness of producers to incorporate these chemicals in their treating chemical programs it was important to study the various application methods by which these products can be introduced into the systems requiring treatment. Since, not all wells are equipped with capillary injection strings, or have backside access to chemical injection other methods such as squeeze applications are considered. Thus, laboratory testing and field test results are discussed in this paper. Background 1Considerable research and development have gone into the development of chemicals to address the problems of paraffin wax accumulation in oilfield production and transport operations. Development of these specialty chemicals requires that meaningful methods of testing be undertaken that will accurately predict the effectiveness of these chemicals in an application. To this end many testing methods have been developed to closely approximate field conditions of temperature, pressure pipeline configuration and pumping requirements. The degree to which these methods correspond to actual field and equipment conditions determines the reliability of such tools as predictive means by which field behavior can be determined. Although the theoretical justifications for the use of these measurement techniques are well founded the acceptance of them, by oil companies, as reliable methods must be thoroughly documented. Documentation of the reliability of these methods requires considerable effort by the service companies who employ them. Many times the documentation is found lacking by the oil companies, and the acceptance of the data generated by these tools and techniques is discounted as virtually meaningless. Thus, service companies are challenged to compare the predictions derived from these laboratory techniques to the effects experienced in field applications. The following discussion will cover some of the laboratory testing conducted, and relate it to the results obtained in field applications of the product chosen from these laboratory tests. Discussion Pour Point and Viscosity Testing ASTM D-97 Pour Point Testing (see figures 1 and 2) has been used for many years as a means of determining the effectiveness of chemical additives on the behavior of waxy crude oils. Can this method be used as the sole criteria for effectiveness? The answer is generally no, however when a crude oil shows a high tendency to congeal or gel and little or no tendency to deposit this test might serve quite well as means of determining an effective treatment. However, viscosity measurements should be conducted in combination with the pour point tests to determine the magnitude of a chemically induced physical change. Why is it necessary to add viscometry measurements to the ASTM D-97 Pour Point data? Pour point measurements involve periodically tilting a tube containing a thermometer and treated or untreated oil samples over a progressively declining temperature range, and observing for movement. The shear imparted by this technique is extremely low, and can represent very small changes in viscosity. Therefore, viscosity measurements avoid the ambiguity introduced by this method. Additional information that is of value in determining the behavior of waxy crude oils under various conditions is also obtainable by the use of viscometry (e.g., yield point, shear stress vs. temperature, and shear stress vs. viscosity etc.).

Abstract To date, field wide CO 2 flooding is continuous or WAG injection processes. In individual wells a huff'n'puff scheme has been used where CO 2 is injected into a well followed by a shut-in period; after a predetermined time, the well is produced. Each of these methods have practical, technical, and economical limitations. This paper describes a new CO 2 injection method that combines all three of these methods but excludes water injection. Continuous CO 2 may be optimal in reservoirs that are not conducive to water injection and do not have CO 2 mobility control problems such as early breakthrough. However, continuous CO 2 requires a large initial CO 2 volume that may be unavailable and relatively expensive. WAG is very common with variations of different ratios of water to CO 2 volumes and tapered ratios. WAG reduces mobility problems and thereby improves areal sweep efficiency; CO 2 purchase expenses may be lower due to the requirement of lower CO 2 volumes. Unfortunately, water injectivity following CO 2 injection may decrease, and the water increases lift and water handling expenses. Huff'n'puff is effective similar to a near wellbore stimulation, but may not realize the benefits of a full field injection program. Also, this adds the complication of injection and production capabilities required in the same well. This may be impossible for some wells on artificial lift. The proposed method is to inject CO 2 and shut in the well similar to the huff and puff, but instead of producing the well inject CO 2 again. This process is a cyclic process like WAG, and shares the variables of the duration and volume of CO 2 injection and the duration of the shut-in period. This method eliminates injectivity and production expenses associated with water. Mobility is controlled by near wellbore achievement of miscibility by the increase in mass transfer between the CO 2 and oil during the shut-in portion of the cycle; i.e. a smaller portion of the reservoir has relatively low viscosity, injected CO 2 due to miscibility between oil and gas occurring nearer the injection well. Introduction The use of CO 2 as a method of enhanced oil recovery has been studied since the early 1950's 1 and its use grew signficantly in the 1970s and 1980s. 2 It is used as an enhanced oil recovery (EOR) process where it is injected following either natural drive or waterflooding in order to recover additional oil. During the life of an oil reservoir, production is usually carried out by primary recovery, secondary recovery, then enhanced oil recovery (EOR). Primary recovery uses the natural energy present in the reservoir to displace oil to the wellbore and includes solution-gas drive, gas-cap drive, natural water drive, fluid expansion, rock expansion, and gravity drainage. Secondary recovery processes add energy to the reservoir by injecting water or immiscible gas and displacing oil to an adjacent producing wellbore. However, because immiscible gases have more mobility problems than water, the secondary recovery stage is almost always carried out with a waterflood. EOR processes are carried out by gas injection, liquid chemical injection and/or the addition of thermal energy. Gas injections are considered EOR processes if the significant recovery mechanisms are not exclusively those of immiscible frontal displacement with high interfacial tension (IFT) relative permeabilities, but include such mechanisms as oil swelling, oil viscosity reduction or favorable phase behavior. The gases used in EOR processes include hydrocarbon gases, CO 2 , nitrogen, and flue gas. Liquid chemicals include polymers, surfactants, and hydrocarbon solvents. Thermal methods include steam drive, cyclic steam flooding, hot water flooding, and in situ combustion. 3

Abstract This paper investigates the effect of higher concentrations (0–100%) of CO 2 , H 2 S, and N 2 on natural gas well deliverability, reserve estimation, and pressure test analysis quantitatively. Physical properties of natural gases such as viscosity and compressibility are corrected according to the concentrations of the contaminant gases such as CO 2 , N 2 , and H 2 S present in it. These contaminant gases have profound impact on pressure test analysis. The Carr et al 1 viscosity correction chart allows adjusting the viscosity up to 15% concentration of these contaminant gases. However, Wichert and Aziz 2 compressibility correction chart allows up to 80% concentration of the CO 2 and H 2 S. Tiab 3 developed an analytical method to estimate pseudopressure function for 0–100% combined-concentration of CO 2 , H 2 S, and N 2 . His pseudopressure was first re-plotted to simplify the procedure and then it was used to analyze the deliverability, pressure tests, and decline curves quantitatively. The analysis was performed with Carr et al 1 viscosity correction chart, pure CO 2 properties, and then with Tiab's corrected pseudopressure. Pure CO 2 properties were used due to the fact that the sample data has 98.256% CO 2 . During this study it was observed that the compressibility factor has a little effect on analysis since it is a volume-related property. Viscosity, however, has the largest effect on the analysis since pressure is transmitted through the fluid in the porous media and viscosity works against it. It was also observed that the numerical method of calculating pseudopressure function introduced successive error in the analysis. Number of pressure data points also contributed to theerrorinnumericalintegrationofthepseudo-pressure function. Analysis of field as well as simulated examples resulted an absolute error range of 13–75% in the permeability estimation in pressure tests, 77% in deliverability tests, and 20–95% with pressure derivative. Error in AOF was observed as 15% and as high as 32 % in reserve estimation. Introduction The High energy (Temperature and Pressure) environment and the presence of Oxygen rich compound turned many of the hydrocarbon reservoirs into CO 2 rich reservoirs. Such reservoirs usually are of low commercial value due to higher concentration of sour gases. Fig.1 shows the existence of CO 2 rich reservoirs in United States. Texas, New Mexico, Colorado, Mississippi, Wyoming, and Utah are the states with abundance of this natural resource. Two major consumers of CO 2 are the Chemical and Petroleum industries. Due to its miscibility in both water and oil, CO 2 has found its niche in EOR operations of miscible flooding. However, the potential for CO 2 flooding and its other application will be significant if it is found in enough quantity. Thus, its use and production as a natural resource requires the development of engineering techniques to analyze such reservoirs effectively.

Abstract Determining the water saturations in thin-bedded turbidites using wire-line logs is difficult; errors in Sw calculation frequently result in uneconomical completions. Consequently, current Brushy Canyon completion decisions include expensive core information to provide an acceptable indicator of oil saturation in order to compensate for the Sw calculation problem. Completion decisions can be improved and less core data is needed using a new method that correlates wire-line logs with core measured bulk volume oil (FS o ). A neural network was trained and tested using density and neutron porosity plus shallow and deep resistivity logs as input variables. The neural network was trained to predict the FS o product from whole core analysis. The trained and tested neural network was then used to estimate FS o in 25 additional Brushy Canyon wells that were not used in the training, but had the same four wire-line logs. A FS o cutoff of 22 units was determined and values greater than the cutoff were summed through the perforated interval in each well. The summed bulk volume oil of the 25 wells was plotted versus the first year's total production. The plot suggests that SFS o greater than 20,000 units will usually result in an economical new well or reentry completion. During the course of optimizing the neural network architecture, valuable insights into network architecture design were gained. For this type of study, less complex architectures produced robust testing results, indicating that the solution, though non-linear, is still reasonably simple. The method should be useful when evaluating behind-pipe completion opportunities in the Brushy Canyon interval of the Delaware Sands in the Permian Basin. Re-completion costs are lower than new well costs; thus thin zones with high values of FS o are potential targets. Introduction The Delaware Mountain Group in the Delaware basin of New Mexico consists of a thick (4500 ft) sandstone and siltstone interval with 95% of the sandstone medium to fine-grained. 1 Porosity and permeability in the productive interval range from 12–25% and 1–5md respectively. 1 Typically the clay content is less than 5%. 1 Stratigraphic divisions are uncertain, 1 but the top of the Lower Brushy Canyon is regionally identified by a kick in the gamma ray and the accompanying resistivity logs. A standard suite of logs includes gamma ray, neutron and density porosity, plus shallow and deep resistivity. Generally the density log produces the best estimate of porosity, but calculating water saturation is problematic. 1 Others 2,3 have reported similar problems in estimating water saturation in thin-bed, low resistivity formations. Around 1990 improved sidewall coring technology resulted in the recovery of samples for laboratory analyses and the ability to accurately record sample depth. Reference 2 recognized the thin-bed, low resistivity problem and developed a procedure to calibrate the available logs with the new core information. The procedure follows: "using the full-core analysis to calibrate log calculations, a procedure was developed to identify the zones that are oil-productive. The procedure is based on the premise that zones with residual oil saturation have a high probability of being productive and zones with no residual oil saturation have a low probability of being productive. By calibrating the Micro Lateral Log to calculate a residual oil saturation value for each one-half foot interval from the digitized log, potential pay zones were identified. By applying porosity correction transforms, setting gamma ray and porosity limits, and calibration of resistivity values, a more accurate determination of the productive intervals was made." Reference 3 recommends accounting for the difference in scale between the point measurements of the core analysis and the lower resolution log measurements by including (adjust log parameters, "m" and "n") the location of each plug in the log interpretation. Both Refs. 2 and 3 are methods of calibrating well-known equations with core information.