Determination Of Oil Saturation Research Articles

A novel method to estimate resistivity index of tight sandstone reservoirs using nuclear magnetic resonance logs

The relationship between resistivity index and water saturation (I-Sw) is very important in formation evaluation via petrophysical data. Low permeability and complicated pore structure make it more difficult to determine I-Sw relationship through rock's electrical property measurements. Nuclear magnetic resonance (NMR) logs are alternative ways to obtain these key parameters. To establish a model to estimate resistivity index from NMR logs, 17 cores from the study area were selected for experiments. The helium porosity, air permeability, NMR T2 distribution, and resistivity of cores were measured. I-Sw relationship was evaluated accordingly. Given these variables, Archie formula, J function, Schlumberger-Doll-Research (SDR) model, and correlation between capillary pressure curve and T2 distribution (Pc-T2) were used to derive a novel method. It aims to calculate resistivity index from T2 time, porosity, and geometric mean of T2 time. The experimental data were applied and the corresponding model was established by multiple statistical regression method. Resistivity index is successfully predicted by T2 distribution. Then, the established model was tested by the experimental data not involved in the modeling. The validation shows that the model is highly precise. Finally, the model was applied to formation evaluation for a field case with satisfactory results. The proposed method and model provide a quantitative basis to analyze and predict resistivity index by well log data. They are of great significance for the accurate determination of oil and gas saturation of tight sandstone reservoirs.

The residual oil saturation determination for Steam Assisted Gravity Drainage (SAGD) and Solvent-SAGD

The residual oil saturation determination is critical for the performance evaluation of any Enhance Oil Recovery (EOR) methods. The existing residual oil saturation determination methods are mainly based on solvent extraction. However, because the quality of the extracted residual oil and the remaining spent rock samples have not been examined before, this study investigates the accuracy of two commonly used solvent extraction methods for the residual oil saturation determination extracted from the spent rock samples of Steam Assisted Gravity Drainage (SAGD) and Solvent-SAGD. The results of the commonly used solvent extraction methods were compared with a new thermal method. It has been found that the thermal method provides more accurate results than solvent extraction method because the reservoir clays interact with residual oil and solvent methods cannot successfully separate the residual oil from reservoir rock. Therefore, a significant amount of clay is detected in the extracted residual oil through solvent extraction. Moreover, this study reveals that among the saturates, aromatics, resins, and asphaltenes fractions of residual oil, the aromatics fraction is responsible for the clay–asphaltene interaction and the resins content reduces this interaction. Because the solvents used to separate residual oil from rock samples are in general strong aromatic solvents, the existing solvent extraction methods fail to determine the residual oil saturation amount accurately.

An innovative technique for determining residual and current oil saturations using a combination of Log-Inject-Log and SWCT test methods: LIL-SWCT

Abstract It is generally recognized that the determination of current oil saturation (Soc) and residual oil saturation (Sor) plays a significant role in production forecasting and the selection and management of enhanced oil recovery (EOR) methods. Failure to accurately determine either saturation state will lead to incorrect recovery estimates and poor understanding of EOR efficacy. While there exist several methods of determining Soc and Sor, each method benefits and suffers from advantages and disadvantages specific to that technique. In order to compensate for the shortcomings of any one specific method, a combination of testing procedures may be utilized. In this paper, we propose a combination of Log-Inject-Log (LIL) and single-well chemical tracer (SWCT) test methods to improve the accuracy of Sor measurement while simultaneously offering a novel approach to the determination of Soc. The proposed method is not still implemented in any field and in this case, the concept is offered, not confirmation through a field example. The LIL method has the advantage of being able to generate a vertical fluid saturation profile throughout a logged interval, but suffers from its strong dependence on porosity assumptions. Subsequently, any deviation between assumed porosity and actual porosity will result in a deviation between measured Sor and true Sor. By comparison, the SWCT test method is independent of porosity, but cannot detect vertical variations in Sor.The complimentary nature of these two test methods, as well as their operational reliance on fundamentally different principles, make them ideal candidates for a hybrid testing program to measure Sor with a high degree of quality assurance. As well, combining the LIL and SWCT test methods in a single testing program offers a novel approach to measuring Soc. The details and mathematical derivation of the theory behind the measurement of Sor and Soc via this hybrid approach are presented in this paper.

Research on the Remaining Oil Starting Mechanism in Different Pores of Polymer Surfactants Using NMR Analysis

With its unique structure and properties, polymer surfactants have been used in chemical flooding. Compared with ordinary polymer, polymer surfactants have a higher recovery degree. However, remaining oil starting mechanism in different pores using different polymer surfactants after water flooding is still unclear. NMR (Nuclear Magnetic Resonance) has a good effect on determination of rock oil saturation and analysis of pore structure. In this paper, oil displacement experiment using kerosene which contains no hydrogen was conducted and the problem caused by the similarity between oil phase relaxation time and water relaxation time in large pores was overcome. Through the change of NMR relaxation time, oil distribution situation in different pores of ordinary polymer, refining III polymer surfactant, and Haibo III polymer surfactant after polymer flooding was measured accurately. This paper also quantitatively analyzed the contribution degree to oil recovery in pores of different sizes, and evaluated oil displacement effect of the above three kinds of oil displacement systems. The results show that when only the swept volume is considered, recovery degree of Haibo III polymer surfactant is higher, reaching 53.66%. In different systems, middle pores contribute most to recovery degree. At the same time, the remaining oil in middle pores and large pores accounts more, which is the main attack direction towards tapping the potential of remaining oil in the oilfield.

Oil-recovery predictions for surfactant polymer flooding

There is increasing interest in surfactant–polymer (SP) flooding because of the need to increase oil production from depleted and water flooded reservoirs. Prediction of oil recovery from SP flooding, however, is complex and time consuming. Thus, a quick and easy method is needed to screen reservoirs for potential SP floods. This paper presents a scaling model that is capable of producing reasonable estimates of oil recovery for a SP flood using a simple spreadsheet calculation. The model is also useful for initial SP design. We present key dimensionless groups that control recovery for a SP flood. The proper physics for SP floods including the optimal salinity in the three-phase region and the trapping number for residual oil saturation determination has been incorporated. Based on these groups, a Box–Behnken experimental design is performed to generate response surface fits for oil recovery prediction at key dimensionless times. The response surfaces derived can be used to estimate the oil recovery potential for any given reservoir and are ideal for screening large databases of reservoirs to identify the most attractive chemical flooding candidates. The response function can also be used for proper design of key parameters for SP flooding. Our model will aid engineers to understand how key parameters affect oil recovery without performing time consuming chemical simulations. This is the first time that dimensionless groups for SP flooding have been derived comprehensively to obtain a response function of oil recovery as a function of dimensionless groups.

Residual Oil Saturation Determination for EOR Projects in Means Field, a Mature West Texas Carbonate Field

Summary The technical success of an enhanced oil recovery (EOR) project depends on two main factors: first, the reservoir remaining oil saturation (ROS) after primary and secondary operations, and second, the recovery efficiency of the EOR process in mobilizing the ROS. These two interrelated parameters must be estimated before embarking on a time-consuming and costly process for designing and implementing an EOR process. The oil saturation can vary areally and vertically within the reservoir, and the distribution of the ROS will determine the success of the EOR injectants in mobilizing the remaining oil. There are many methods for determining the oil saturation (Chang et al. 1988; Pathak et al. 1989), and these include core analysis, well-log analysis, log/inject/log (LIL) procedures (Richardson et al. 1973; Reedy 1984), and single-well chemical tracer tests (SWCTT) (Deans and Carlisle 1986). These methods have different depths of investigation and different accuracies, and they all provide valuable information about the distribution of ROS. No single method achieves the best estimate of ROS, and a combination of all these methods is essential in developing a holistic picture of oil saturation and in assessing whether the oil in place (OIP) is large enough to justify the application of an EOR process. As Teletzke et al. (2010) have shown, EOR implementation is a complex process, and a staged, disciplined approach to identifying the key uncertainties and acquiring data for alleviating the uncertainties is essential. The largest uncertainty in some cases is the ROS in the reservoir. This paper presents the results from a fieldwide data acquisition program conducted in a west Texas carbonate reservoir to estimate ROS as part of an EOR project assessment. The Means field in west Texas has been producing for more than the past 75 years, and the producing mechanisms have included primary recovery, secondary waterflooding, and the application of a CO2 EOR process. The Means field is an excellent example of how the productive life and oil recovery can be increased by the application of new technology. The Means story is one of judicious application of appropriate EOR technology to the sustained development of a mature asset. The Means field is currently being evaluated for further expansion of the EOR process, and it was imperative to evaluate the oil saturation in the lower, previously undeveloped zones. This paper briefly outlines the production history, reservoir description, and reservoir management of the Means field, but this paper concentrates on the residual oil zone (ROZ) that underlies the main producing zone (MPZ) and describes a recent data acquisition program to evaluate the oil saturation in the ROZ. We discuss three major methods for evaluating the ROS: core analysis, LIL tests, and SWCTT tests.

Accurate Oil-Saturation Determination and Monitoring

This article is a synopsis of paper SPE 46245, "Accurate Oil-Saturation Determination and Monitoring in a Heavy-Oil Reservoir," by Paul Harness, SPE, and Noel Shotts, SPE, Texaco E&P Inc.; Jim Hemingway and David Rose, GeoQuest; and Roy van der Sluis, SPE, Schlumberger Wireline and Testing, originally presented at the 1998 SPE Western Regional Meeting, Bakersfield, California, 10-13 May.

Redesigned Ester Single-Well Tracer Test That Incorporates pH-Driven Hydrolysis Rate Changes

Summary The rate of alkyl ester hydrolysis was found to be sensitive to the pH changes that occurred during application of the single-well tracer test (SWTT) in both sandstone and turbidite reservoirs. Detection methods, an improved test sequence, and the detrimental consequences that this variable can have on oil saturation determination are discussed.

Experimental Aspects of Partitioning Tracer Tests for Residual Oil Saturation Determination With FIA-Based Laboratory Equipment

Summary Partitioning tracer tests are used to determine residual oil saturation (ROS). At Koninklijke/Shell Laboratorium, Amsterdam, laboratory equipment based on the flow injection analysis (FIA) method has been constructed for rapid (within 2 hours) and accurate (better than 8%) determination of the equilibrium partition coefficient of tracers between crude oil and brine under simulated reservoir conditions. The apparatus makes possible investigation of the influence of all relevant parameters on the partition coefficient: tracer type and concentration, crude oil type, pressure (up to 34 MPa [4, 930 psi]), GOR's, temperature (up to 150°C [302°F]), and brine salinity. The FIA equipment has been critically evaluated with model compounds. Its versatility has been verified with experimental results obtained on dead and live crudes.

Evaluation and Comparison of Residual Oil Saturation Determination Techniques

SummaryThe amount and distribution of residual oil saturation (ROS) are critical parameters for determining whether to apply an EOR process to a reservoir. A brief review of available ROS techniques is presented, indicating advantages, limitations, problems, and possible improvements of each technique. Advantages and disadvantages of each ROS-determination technique are summarized. Screening criteria for determining the best ROS technique under certain wellbore or reservoir conditions are presented.This paper also presents results from comparisons of ROS measurements obtained from the literature as calculated from resistivity logs, pulsed neutron capture (PNC) logs, pressure coring, single-well tracer tests, nuclear magnetism logs (NML), carbon/oxygen (C/O) logs, and electromagnetic propagation tool (EPT) measurements. In this study, the ROS measured by each method is compared with that determined by other methods conducted in the same well. The comparison shows that average values of ROS determined by C/O log, PNC-LIL (log-inject-log), and single-well tracer test do not differ statistically when compared with other methods. The resistivity log tends to give higher than average [2 saturation units (s.u.)] ROS measurements, while pressure coring tends to give lower than average (4 s.u.) ROS values. EPT and NML show deviations of about 8 s.u. of ROS values from other methods, which indicates a statistically significant difference.ROS vertical profiles obtained by two different methods from the same well were compared to eliminate the ROS variation resulting from formation depth. The vertical profiles based on ROS zoning and foot-by-foot measurements were studied to provide more "resolution" for comparisons. The results show that discrepancies in measurement methods are more pronounced when vertical profiles are divided into different zones. This could mean that the discrepancies are much greater for some zones than for others. This approach offers the possibility of studying ROS-method discrepancies as a function of different ROS values.

The Role of Oxidizing Agent in the Chemistry of In-Situ Uranium Leaching

Abstract A one-well test to evaluate reservoir properties that govern the restorability of a zone in an underground aquifer to be solution mined for uranium has been considered. The test involves injection of a relatively small volume of leach solution and subsequent production of a larger volume of fluid. Two important parameters-cation exchange capacity and an equilibrium constant--are determined by history matching the effluent composition. Two different solution techniques are used. By neglecting dispersion and reservoir heterogeneities, an analytical solution based on the method of coherence provides considerable insight into the pertinent features of the production composition history. To include complexities such as dispersion and layering, a two- dimensional finite difference computer simulation is used. A number of different approaches have been evaluated. The most reliable approach is to use laboratory tests to determine one parameter with core samples and to use production history to determine the other parameter. Measurements of both anion and cation effluent concentrations are required to implement this procedure. Introduction A one-well push-pull test is one possible technique to assess the potential of in-situ uranium leaching and subsequent restoration of a contaminated mineralized zone. To address the latter, the test must be able to measure cation selectivity K12 and exchange capacity Qv in-situ from an electrolyte concentration effluent history. The adsorption parameters K12 and Qv are important factors that affect the restoration process. Other parameters that also may affect restoration are formation heterogeneities, longitudinal and transverse dispersion, injection concentration, and well placement. The purpose of this paper is to show how and to what extent the adsorption parameters can be obtained from push-pull test data and the sensitivity of the effluent history to the various factors mentioned. This is accomplished by two techniques: the coherence method, which neglects dispersion and assumes homogeneous media, and a two-dimensional finite difference solution of the appropriate concentration balance equation, which takes dispersion into account and can include heterogeneity. The one-well push-pull test consists of lixiviant injection followed by production of pregnant solution, all conducted through the same wellbore. This test is analogous to the Exxon tracer test for residual oil saturation determination. Fig. 1 shows a cross section in a three-layer reservoir. During injection (injection cycle) the fluid moves radially outward from the wellbore. At the end of the injection cycle, production may be delayed (soaking period) before production begins (production cycle). The time periods for the three cycles are referred to as tI, tS and tP in later discussions. Mathematical Development The mathematical formulation is restricted to restoration (cation exchange). Uranium production and history matching will be considered in a subsequent publication. The following assumptions and idealizations have been made in the development of the models.The theory is presented in radial geometry.Permeability and porosity vary with depth only.The fluid is both single phase and incompressible.The mobilities of injected and formation fluids are equal.Cation exchange is the only mechanism of adsorption and the exchange sites can be characterized by a single free energy (equilibrium constant). SPEJ P. 141^

A Recipe for Residual Oil Saturation Determination

Before initiation of a CO2 tertiary recovery project, a residual oil saturation study was conducted in the deep, hot, pilot reservoir. The paper discusses the many technical problems that had to be resolved before and during the study. The problems confronted are outlined so that the procedure can be used much like a cookbook in designing future studies in similar reservoirs. Introduction With the advent of increased oil prices, tertiary recovery techniques are becoming more economically attractive. The necessity for residual oil saturation measurements will become more common since these numbers are mandatory in defining the profitability of any tertiary project. Routine procedures to measure this saturation in situ become necessary. However, we are dealing with such a delicate system that the details of planning such an operation become very involved.In 1978 Shell Oil Co., in conjunction with the U.S. DOE, conducted a residual oil saturation study in a deep, hot, high-pressured U.S. gulf coast reservoir. The work was conducted before initiation of a CO2 tertiary recovery pilot.Primary discussion in this paper centers around planning and results of a "log-inject-log" (LIL) operation used as a prime method to determine the residual oil saturation. Several independent methods were used to calculate the residual oil saturation in the subject well in an interval between 12,910 and 12,920 ft (3935 and 3938 m). In general, these numbers were in good agreement and indicated a residual oil saturation between 22 and 24%.A free-gas saturation was measured in the residual oil saturated interval. This saturation may well be typical of U.S. gulf coast reservoirs that are below the original bubble point at the time tertiary recovery is initiated. As a result, residual oil saturation typically may be less than those values determined by "flood pot" or countercurrent imbibition tests run in the laboratory. Likewise, residual saturations conventionally measured by openhole resistivity and porosity logs may be residual hydrocarbon and not residual oil saturations.The test was conducted in the "S" Sand Reservoir B (SRB), a 12,800-ft (3901-m) deep U.S. gulf coast reservoir in Weeks Island field, Iberia Parish, LA. The project setting is depicted in Fig. 1. The SRB initially contained two oil columns with more than 3 million bbl (476,700 m3) of in-place oil. Virtually all of this was in the pilot area. Before initiation of the tertiary project, the SRB had been flooded with fresh water. The remaining oil column had been produced to an estimated thickness of 23 ft (7 m). The 900 acre-ft (1 110 140 m3) of the SRB we propose to displace should contain a minimum of 258,000 bbl (40 996 m3) of water-drive residual oil. If the process is proved successful in the SRB, other major watered-out reservoirs in Weeks Island field have an estimated tertiary potential of 26 million bbl (4 131 400 m3) of oil which could be recovered by CO2 displacement. JPT P. 1999＾

Determination of Oil Saturation After Waterflooding in an Oil-Wet Reservoir The North Burbank Unit, Tract 97 Project

Laboratory and field techniques for measuring oil saturation were applied to an oil-wet reservoir. Log-inject-log and core measurements confirmed a 3.1 saturation exponent. Ultimate residual oil saturations determined by log-inject-log, core analysis, and microlaterolog procedures using laboratory-determined cementation and saturation exponents were in good agreement. Introduction In evaluating the prospects for commercial application of enhanced recovery processes, one of the most important factors to be considered is the quantity and distribution of oil present in the pore space at the time the process is to be applied. Waterflooding tends to leave low oil saturations in high-permeability zones and high saturations in tighter zones. Where expensive processes are to be applied, it is vital that the oil saturation distribution be established as accurately as possible. We have avoided the term "residual oil" because it is not precisely defined in the literature. Instead, the term "ultimate residual" is used to describe thoroughly flushed sand near the end-point of the relative permeability curve, and "current oil saturation" refers to the oil permeability curve, and "current oil saturation" refers to the oil saturation at some defined point in the production history of a reservoir. It is difficult to determine the oil saturation in a waterflooded reservoir for tertiary recovery purposes because there is some mobile oil present and significant changes can occur during drilling or coring. During the past few years, the rapid expansion of field testing of past few years, the rapid expansion of field testing of tertiary recovery processes using expensive chemical fluids has accentuated the importance of upgrading the accuracy of determination of oil saturation after secondary recovery. The industry has responded with several useful techniques, including special coring, logging, and tracer procedures. A number of excellent papers have been published giving details of these methods. This paper reports on the application of several techniques to a paper reports on the application of several techniques to a strongly oil-wet reservoir - the North Burbank Unit Tract 97 area. Nature of the Reservoir The North Burbank reservoir, which lies at a depth of about 3,000 ft, is a relatively clean, well consolidated sandstone of a type that occurs in many fields of north-eastern Oklahoma. The sand averages 47.2-ft net thickness, 16.8-percent porosity, and 50-md permeability. The stock-tank oil has a gravity of 39 degrees API. Tract 97, where the tertiary pilot is being run, is one of the most homogeneous areas of the North Burbank field. There are frequent, thin, shale laminae, but these do not interfere markedly with vertical fluid movement. Dispersed shales occur occasionally in the sand column, but water-sensitive clays have not been observed in the North Burbank reservoir. It long has been known that the North Burbank reservoir is strongly oil-wet. During the development of the waterflood, at least two wells on each quarter section were cored and, at frequent intervals, a wettability index designated as the Amott-Harvey "relative displacement index" has been run. This technique, which is similar to the Amott wettability measurement, compares the tendency of a permeability plug at irreducible oil to imbibe oil with the tendency of the same plug at irreducible water to imbibe water. The results are expressed as numbers ranging from − 1.0 (oil-wet) to + 1.0 (water-wet). Details of the procedure are given in Ref. 8. There is always some variation from specimen to specimen within a well, and from well to well, but the average over the North Burbank Unit is -0.7, strongly oil-wet. JPT P. 491

Utilization of Waxman-Smits Equations for Determining Oil Saturation in a Low-Salinity, Shaly Sand Reservoir

The Waxman-Smits equations have been applied in a shallow, shaly sand, low-salinity reservoir to determine if oil saturation can be reliableestimated. Known in-situ oil saturations were used as the standard ofcomparison. Results indicate that the Waxman-Smits equations can becombined with independently, determined parameters to produce reasonableestimates of oil in place for the reservoir studied. Introduction A significant portion of the reserves in California exist inshallow shaly sand reservoirs. Oil gravity in many ofthese reservoirs is very low. Therefore, significantvolumes of oil remain in the reservoirs following primarydepletion and become targets for secondary or tertiaryrecovery projects. Accurate estimates of oil in place arerequired for planning these relatively expensive projects. Determination of oil saturation in clayey reservoirshas long been a challenge because of the complexities ofthe clay conductance mechanism. Additional complexitiesin many shallow California fields are very low watersalinities and uncertainties in water resistivities causedby interzone mixing, water injection, etc. Because ofthese complexities, oil saturations derived from log datahistorically have been highly uncertain to the extent thatcores or other means have been relied upon for saturationestimates. A resistivity model for describing effects of dispersedclays in oil-bearing shaly sands has been described byWaxman and Smits and by Waxman and Thomas. The objectiveof this study was not to verify the Waxman-Smits equations;these equations have been confirmed experimentally for awide range of conditions. Instead, the objective of thisstudy was to apply the equations to determine whether oilsaturation could be reliably predicted in uncored wells inthese shallow, fresh-water, shaly sand reservoirs. A reservoir where oil saturation could be determinedby independent means was chosen for the study. Thisreservoir is considered to be a severe test of the equationsbecause of the wide variations in clay content andsaturations and the low-water salinity. Because of thesensitivity of the calculated saturations to variationsin the input parameters, determination of these parametersare discussed in detail. Determination of In-Situ Oil SaturationFrom Cores In-situ oil saturation normally cannot be determined fromlaboratory measurements because of flushing of the oil bythe coring fluid and blowdown effects. However, theKern River field in California is an exception. As a resultof very high oil viscosity at Kern River (about 3,000 cp), laboratory measurements of oil volume in plugs cut fromthe center of large-diameter (5 1/4-in.) cores can be used toestimate in-situ oil saturation. Using tritium tracers, invasion in cores in the KernRiver field has been shown repeatedly to be minimalwhen the coring program is properly designed and controlled.Concentration of the tritium in the mud is monitoredcontinuously while coring. Small center plugs are cut forconventional laboratory analysis and for measurement oftritium concentration in the extracted fluids. Theratio of the tritium concentration in the core plug, C, tothat in the coring fluid, Co, is indicative of mud filtrateinvasion. For the Kern River field, this ratio is normallyless than 5 percent. JPT P. 1204