Use of Capillary-Pressure Data for Rapid Evaluation of Formation Damage or Stimulation

1986 ◽  
Vol 1 (02) ◽  
pp. 131-142 ◽  
Author(s):  
J.O. Amaefule ◽  
S.T. Masuo
Keyword(s):  
Capillary Pressure ◽  
Formation Damage ◽  
Rapid Evaluation ◽  
Pressure Data

New Relationship Between Resistivity Index and Relative Permeability

2015 ◽  
Vol 137 (3) ◽  
Author(s):  
Dong Ma ◽  
Changwei Liu ◽  
Changhui Cheng
Keyword(s):  
Capillary Pressure ◽  
Relative Permeability ◽  
Pressure Data ◽  
Two Phase ◽  
Resistivity Index ◽  
Proposed Model ◽  
Petrophysical Parameter ◽  
Oil Water ◽  
Better Than ◽  
Good Agreement

Relative permeability as an important petrophysical parameter is often measured directly in the laboratory or obtained indirectly from the capillary pressure data. However, the literature on relationship between relative permeability and resistivity is lacking. To this end, a new model of inferring two-phase relative permeability from resistivity index data was derived on the basis of Poiseuille's law and Darcy's law. The wetting phase tortuosity ratio was included in the proposed model. The relative permeabilities computed from the capillary pressure data, as well as the experimental data measured in gas–water and oil–water flow condition, were compared with the proposed model. Both results demonstrated that the two-phase permeability obtained by proposed model were generally in good agreement with the data computed from capillary pressure and measured in the laboratory. The comparison also showed that our model was much better than Li model at matching the relative permeability data.

Formation Damage Issues Impacting the Productivity of Low Permeability, Low Initial Water Saturation Gas Producing Formations

2005 ◽  
Vol 127 (3) ◽  
pp. 240-247 ◽  
Author(s):  
D. Brant Bennion ◽  
F. Brent Thomas
Keyword(s):  
Capillary Pressure ◽  
Water Saturation ◽  
The United States ◽  
Gas Production ◽  
Pressure Effects ◽  
Formation Damage ◽  
Low Permeability ◽  
Gas Reservoirs ◽  
Initial Water ◽  
The Impact

Very low in situ permeability gas reservoirs (Kgas<0.1mD) are very common and represent a major portion of the current exploitation market for unconventional gas production. Many of these reservoirs exist regionally in Canada and the United States and also on a worldwide basis. A considerable fraction of these formations appear to exist in a state of noncapillary equilibrium (abnormally low initial water saturation given the pore geometry and capillary pressure characteristics of the rock). These reservoirs have many unique challenges associated with the drilling and completion practices required in order to obtain economic production rates. Formation damage mechanisms affecting these very low permeability gas reservoirs, with a particular emphasis on relative permeability and capillary pressure effects (phase trapping) will be discussed in this article. Examples of reservoirs prone to these types of problems will be reviewed, and techniques which can be used to minimize the impact of formation damage on the productivity of tight gas reservoirs of this type will be presented.

Application of Air-Mercury and Oil-Air Capillary Pressure Data In the Study of Pore Structure and Fluid Distribution

1966 ◽  
Vol 6 (01) ◽  
pp. 55-61 ◽  
Author(s):  
J.J. Pickell ◽  
B.F. Swanson ◽  
W.B. Hickman
Keyword(s):  
Interfacial Tension ◽  
Pore Structure ◽  
Capillary Pressure ◽  
Fluid Distribution ◽  
Pore Geometry ◽  
Residual Oil ◽  
Pressure Data ◽  
Oil Saturation ◽  
Residual Oil Saturation ◽  
Phase Saturation

Abstract Many physical properties of the porous media-immiscible liquid system are dependent upon the distribution of fluids within the pores; this in turn, is primarily a function of pore structure, liquid-liquid interfacial tension and liquid-solid wetting conditions. The capillary pressure hysteresis process provides a means of investigating the influence of pore structure upon fluid distribution for consistent surface conditions. Investigations indicate that residual non-wetting-phase saturations following the imbibition process (i.e., wetting phase displacing non-wetting phase) are dependent upon both pore structure and initial non-wetting phase saturation and suggest that residual fluid is distributed to discontinuous globules, one to a few pore sizes in dimension, through the entire range of pore sizes originally occupied. It appears that air-mercury capillary pressure data adequately reflect the distribution of fluids in a water-oil system when strong wetting conditions prevail. An oil-air counter-current imbibition technique has also been found to provide a rapid means of obtaining residual-initial saturation data. In a majority of cases, residual saturations determined from the oil-air or air-mercury process reasonably approximate residual oil and saturation following water drive of a strongly water-wet medium. Introduction A reliable estimate of recoverable reserves depends not only on the amount of original oil-in-place but also on pore geometry and distribution of fluids within the pores. A critical parameter determining the recovery from a reservoir under waterflood, for example, is the amount and distribution of residual oil within the various rock types present. The purpose of this paper is to investigate the mechanism of capillary trapping and assess its importance in laboratory measurements of residual oil saturation. The degree of wettability of a reservoir rock is recognized as an important factor in waterflood or imbibition experiments. In this paper, however, only the water-wet case has been considered. Considerable experimental evidence1 suggests that for water-wet rocks, capillary forces predominate in the distribution of fluids and that viscous forces in the range normally of interest in the reservoir have a minimum influence on residual oil saturation. It follows that if the ultimate recovery is controlled by pore geometry, a unique residual non-wetting phase saturation should exist for a given set of initial conditions. Two laboratory procedures found to be extremely useful in the study of pore structure and degree of fluid interconnection at various saturations are described. Although air-mercury capillary injection curves have been used2 previously to characterize the drainage case, the withdrawal or imbibition case can provide valuable supplementary data. The air-mercury process, however, has several disadvantages; it is difficult to run in a sufficiently accurate manner, mercury does not always act as a strongly non-wetting liquid and in the air-mercury process the sample is rendered unsuitable for future analyses. An alternative process is described in which air is the non-wetting phase and naptha, heptane, octane or toluene is the wetting phase. Interfacial Tension and Capillary Pressure Interfacial tension between immiscible fluids is due to the difference in attraction of like molecules as compared with their attraction to molecules of the neighboring fluid. This net attraction results in a tension at the interface. To extend the interface; thus, interfacial tension s can also be thought of as free surface energy. Interfacial tension is normally expressed as dynes/cm, and interfacial energy is measured in ergs/cm2 hence, both have dimensions mLt-2 and are numerically equal.

Sign in / Sign up

Export Citation Format

Share Document