Determination Of Residual Oil Saturation Research Articles

Study on determination of residual oil saturation in waterflooded zones

Study on determination of residual oil saturation in waterflooded zones

Measurement of partition coefficients of phenol and cresols in gas-charged crude oil/water systems

An instrument has been constructed for monitoring the partition coefficients of phenol and cresols between crude oil and water under sub-surface conditions. The device has the capacity for introducing methane gas into crude oil, thereby allowing measurements under live oil (solution gas-containing) conditions. The partition coefficients of phenol and cresols have been measured in crude oil: water substrates under “live” oil and “dead” oil (without solution gas) conditions over a temperature range 25–150 °C. Over the range investigated it is seen that the introduction of gas (crude oil saturated at 100 bar with methane) into the system resulted in an approximate doubling of partition coefficients compared to the equivalent dead oil: brine systems. The partition coefficient data obtained using the device may be employed in a number of petroleum exploration and production activities such as the determination of residual oil saturation of a water-flooded petroleum reservoir. Partition coefficient measurements may help in predicting toxic organic solute loadings in oilfield discharge waters.

Determination of Residual Oil Saturation by Use of Enhanced Diffusion

Summary The enhanced diffusion method (EDM) exploits the diffusion contrast between oil and water separating their respective nuclear magnetic resonance (NMR) signals. Unlike standard NMR logs acquired with short interecho time (TE), measurements, EDM data are acquired using long TE accentuating diffusion. Fundamentally the EDM establishes an absolute upper bound for the T2 of water, thus any T2's greater than this limit unambiguously indicates that oil is present. The EDM's best application is with intermediate viscosity oils (approximately 1 to 50 cp) complementing other NMR hydrocarbon-typing applications designed for lighter hydrocarbons (i.e., the differential spectrum method). While expanding the viscosity range of NMR hydrocarbon-typing applications, the EDM also provides a method by which to determine residual oil saturation (ROS), which is the main focus of this article. The potential use of NMR as a direct indicator of hydrocarbon saturation via techniques such as the differential spectrum method (DSM) has generated significant interest in the petrophysical community in recent years. Although originally developed for applications involving natural gas, the DSM has also been used successfully in light hydrocarbon environments. However, success has been limited to the low end of the viscosity spectrum because of the T1 separation requirements between the brine and hydrocarbon phases. The T1 separation requirement imposed on diffusion applications in higher viscosity oils can be eliminated by using the EDM, where diffusion is turned into the dominant relaxation mode for the wetting brine phase. Given that brine is more diffusive than the hydrocarbons, the longest apparent T2 from the brine phase can be made short enough to cause separation between the two phases in T2 space, thereby eliminating the need for T1 separation. Wait time manipulation can then be used to quantify hydrocarbon volumes when the two phases are separated in the T2 domain. In this article we focus on determination of the residual oil saturation using the EDM, while also providing guidelines for job screening and acquisition parameter selection. Several case histories that are provided are used to illustrate the basic concepts and different methodologies available.

Determination of Residual Oil Saturation from Well Logs

Abstract New techniques of determining residual oil saturation from logs are proposed. The inherent technical constraints, such as “stripping”, are discusssed.

Carbon Dioxide Flooding-fundamentals

Introduction This is the first of two papers dealing with the fundamentals and application of carbon dioxide flooding. First, the basic mechanism involved is discussed. Then a laboratory experimental program as well as predictive techniques to determine the minimum miscibility pressure, swelling of oil, viscosity reduc tion, PVT properties, solution gas drive effect and increased injectivity are presented. Finally, laboratory tests directed toward the determination of residual oil saturation and the anticipated incremental oil recovery are discussed. Introduction Since 1950, the petroleum industry has been carrying out considerable research into the use of Carbon dioxide to increase the recovery of oil from underground hydrocarbon reservoirs(22). In the last few years, about a dozen new field applications have been initiated and more could come if economically priced CO2 supplies are found. Most petroleum research centers have projects relating to CO2 flooding, indicating the current interest in CO2 flooding and promising further innovations in the process. This paper deals with the fundamentals and the research aspects of carbon dioxide flooding. The basic mechanisms which may lead to an increased oil recovery, the data required to evaluate a potential application in the field, certain basic properties of CO2 and carbonated fluids, and the all-important considerations of residual oil and incremental oil recovery are described and discussed. A second paper covers the reservoir engineering aspects of field applications, such as selecting a reservoir suitable for CO2 flooding, determining the CO2 requirements, injection/production strategies and certain recommendations regarding pilot testing the process in the field. Basic Mechanisms Carbon dioxide flooding may be applied in the field as a secondary or tertiary process and would normally involve the injection of CO2 and some other fluids, either sequentially or in an alternating fashion. Generally, in reservoirs in which the displacement is horizontal or nearly so, the CO2 flooding process would involve alternating injection of CO2 and water to attempt to control the mobility of the fluids, whereas in vertical floods the various fluids would be injected sequentially. For example, in vertical downward displacement, the CO2 may be followed by a lighter gas to maximize the advantage of gravity segregation and minimize -viscous and gravity" fingering; in vertical upward displacement, CO2 would be followed by water, again taking advantage of the gravity segregation. Regardless of how CO2 flooding is applied in the field, the following factors may contribute to increasing the oil recovery:reduction of crude oil viscosity;swelling of crude oil;miscibility effects;increase of injectivity;internal solution gas drive. The effects of the foregoing on oil recovery have been discussed in the literature(12,22). Therefore, only the new and hitherto unrecognized aspects will be discussed here. With regard to swelling of crude oil, the additional oil recovery has generally been considered to be due to an increase in the oil formation volume factor so that the residual oil is smaller in volume at surface separator conditions.

Determining Swept-Zone Residual Oil Saturation in a Slightly Consolidated Gulf Coast Sandstone Reservoir

This paper reviews quantitative determinations of swept-zone residual oil saturation in the slightly consolidated sandstones of the Tertiary System of the Gulf Coast. Different residual oil saturation measuring techniques were evaluated. Results obtained from all techniques showed good agreement of residual oil saturation values among the different techniques. Introduction The volume of oil remaining in major reservoirs after water floodout is potentially attractive for tertiary projects. However, an accurate determination of residual projects. However, an accurate determination of residual oil saturation (Sor) is essential for every reservoir, not only to evaluate the potential for tertiary recovery, but also to understand a waterflooded reservoir's current performance. performance. Evaluation of primary and secondary production mechanisms and ultimately, the prediction of potential tertiary reserves, hinge on the Sor-porosity product, (Sor phi). Yet, the determination of Sor (assuming porosity can be determined accurately) has not been easy porosity can be determined accurately) has not been easy to achieve in the soft formations of south Louisiana. Mechanical problems with tools and techniques together have made this important parameter difficult to obtain. Thus, evaluation of the most promising of the existing Sor measuring techniques was necessary to provide guidance for future determinations. The reservoir chosen for this vanguard effort was the 7,800-ft (2400-m) "Q2" sand of Reservoir A in the Main Pass Block 69 Field, offshore Plaquemines Parish, LA (Fig. 1). The "Q2" Sand is an upper Miocene, fault-controlled, deltaic formation and was produced first in the Reservoir A fault block in 1956. Fig. 2 is a log section showing the Sor project well, S.L. 1357 No. 46, and a nearby well, S.L. 1357 No. 16. Stringer drainage and uneven water encroachment are common in this multilayered reservoir (Figs. 2 and 3). The original reservoir pressure was 3,700 psi (25.5 MPa) which had dropped to about 3,000 psi (20.7 MPa) before water injection began. The reservoir pressure is now stabilized at about 2,500 psi (17.2 MPa). Initially, the crude oil was saturated and the reservoir had an original gas cap (Fig. 4). At the onset of this test, the best estimate for Sor in the good quality rock in the "Q2" sand of Reservoir A was about 20 to 30%; however, a good chance of significant error in this estimate existed. Therefore, Shell wanted to determine as accurately as possible the swept-zone residual oil saturation for this major reservoir. Well S.L. 1357 No. 46, a field development well, was chosen for this project. Because it was recognized that this would be a difficult project, many man-months were spent in, planning. Every effort was made to anticipate technical problems and many of the staff at Shell Development Co.'s Bellaire Research Center worked to find solutions. Wellsite work was supervised closely by experienced personnel from the Coastal Div. and the research center. This supervision included continuous calculating and monitoring. This ensured that all necessary data of good quality were gathered. Presentation of Operations Presentation of Operations Fig. 5 compares the schematic hole profile and penetration rate plot for this well with the sand section depicted penetration rate plot for this well with the sand section depicted by a dual induction log. JPT P. 513

Determination of Residual Oil Saturation from Geophysical Well Logs in Tertiary Recovery Projects

Abstract Residual oil saturation (ROS), a key factor in the planning of tertiary recovery projects, can be determined on the basis of reservoir engineering concepts, core data, single-well tracer tests, and specialized geophysical well-logging techniques. Uncertainty limits of conventional logging techniques are not too promising. However, several log-inject-log techniques using multiple repeat logging runs will determine residual oil saturation within the range of ROS ± (≤ 5 saturation percent). Engineered planning of both logging and injection procedures is a prerequisite for reliable log-derived ROS estimates.