George V. Chilingarian

Surface operations in petroleum production

1. Introduction (G.V. Chilingarian, J.O. Robertson, Jr. and C. Thibault with Appendix by D.D. Coleman). 2. Flow Rate Measurement (T.R. Sifferman with Appendix by L.J. Kemp and G.V. Chilingarian). 3. The Manufacture, Chemistry and Classification of Oilwell Cements and Additives (J.O. Robertson, Jr., G.V. Chilingarian and S. Kumar). 4. Fracturing (J.O. Robertson, Jr., G.V. Chilingarian and S. Kumar). 5. Acidizing Oilwells (J.O. Robertson, Jr. and G.V. Chilingarian). 6. Gravel Packing (W.B. Hatcher, G.V. Chilingarian and J.R. Solum). 7. Steam Enhanced Oil Recovery (J.P. Fanaritis and G.V. Chilingarian). 8. Corrosion in Drilling and Producing Operations (T.A. Bertness, G.V. Chilingarian and M. Al-Bassam). 9. Water Quality for Subsurface Injection (C.C. Wright and G.V. Chilingarian). 10. Offshore Technology (S. Kumar and G.V. Chilingarian). 11. Pollution Control (K.M. Sasseen, G.V. Chilingarian and J.D. Brady). 12. Underground Storage of Gas and Oil (A. Ali Azun, G.V. Chilingarian and S. Kumar). Appendix A. Technology of Testing Petroleum Products and Sample Experiments (G.V. Chilingarian, J.O. Robertson, Jr. and C.M. Beeson). Appendix B. Conversion of Units (J.O. Robertson Jr. and G.V. Chilingarian). References Index. Subject Index.

Simple quantitative evaluation of porosity of argillaceous sediments at various depths of burial

Abstract Relationship of porosity (φ) to depth of burial (D, in m), geologic age (A, in millions of years), and lithology (ratio of thickness of shales/total thickness of terrigenous deposits = R) has been developed by the writers, which gives satisfactory results: φ=φ 0 exp −0.014(13.3 log A−83.25 log R + 2.79)×10 −3 D where φ0 = initial porosity of the argillaceous sediment. A nomogram has been prepared for an easy solution of the above equation.

Chapter 4 Diagenesis and Origin of Porosity

Publisher Summary This chapter discusses the most important aspects of diagenesis as they relate to the processes and spectrum of geologic environments by and in which porosity in carbonate sediments and rocks can be modified. Diagenetic alterations of carbonate sediments and rocks are known to occur in environments from subaerial meteoric to shallow and deep marine, and shallow to progressively deeper burial subsurface zones. Porosity in limestones and dolomites forms by a myriad of complex processes operative from the time of deposition (eogenetic) and continuing into deep-burial (mesogenetic) and subsequent meteoric exposure (telogenetic) environments. Porosity systems in carbonate rocks likewise are complex, and reservoirs typically are composed of several pore types, including those that are of primary as well as secondary origin. Such complexity in the modes of porosity evolution commonly results in extreme lateral and vertical heterogeneity in carbonate reservoirs. Porosity may or may not be coincident with particular depositional facies and, similarly, pores created or occluded in one diagenetic environment may conversely be occluded or exhumed later in another diagenetic environment.

Data on consolidation of fine-grained sediments

ABSTRACT In this paper, some of the previous research of the authors and their students on the subject of the consolidation of fine-grained sediments is reviewed, and additional experimental data is presented. An analysis of pressure vs. moisture content curves for these sediments has led to the overall conclusion that upward deviations of the curve from linearity are caused by the squeezing out of non-oriented water first. These deviations occur at pressures corresponding to about 20-25% remaining moisture content for kaolinite, and about 50-70% for montmorillonite, that is, at pressures where the chemistry of the squeezed-out solutions begins to change appreciably. The experimental results also indicate that the salinity of interstitial solutions in shales should be less than that of water i associated sandstones, assuming that water was squeezed from the shale into the sandstone.

Abnormal formation pressures and their detection by pulsed neutron capture logs

Abstract The present paper highlights the importance of abnormal formation pressure environments in oilfield operations. The detection and quantitative evaluation of overpressured formations is critical to exploration, drilling, and production operations involving hydrocarbon resources. As a result, an interdisciplinary technical team approach is required to optimize the safety, engineering, and financial aspects of operating in such hostile subsurface environments. Pulsed neutron capture (PNC) logging devices can be used for detection and quantitative evaluation of overpressure environments through the drillpipe and to monitor pressure depletion behind casing. Field observations clearly indicate that the Σ-values in shale formations decrease in a regular fashion with depth in normally compacted clastic sequences. Abnormal formation pressures are, however, flagged by divergence from this normal Σ-trend. Several field examples are presented to illustrate applications of PNC logging devices.

Influence of Porosity and Direction of Flow on Tortuosity in Unconsolidated Porous Media

Tortuosity tau is defined as the square of the ratio, phi-range of the effective length of pore channels to the length parallel to the overall direction of the pore channels in a porous medium. It has significance in interpreting the hydraulic and electric proper ties of porous media. In this study, experimental results of tortuosity and porosity phi were investigated in relation to different directions of flow in various unconsolidated porous media. When the media (mica, textile fibers, kaolinite, and bituminous soil, with a high phi-range of between 60 - 90 %) are exposed to flow perpendicular to the planes and fibers, tau responds positively to phi. When the media (randomly packed beds of spheres, with a medium phi-range of between 34 - 45 %) are exposed to flow parallel to the planes, tau responds negatively to phi. When the media (glass powders, glass spheres, dry soil, quartz sand, and white sand, with a variety of grain sizes and a medium porosity phi-range of between 37 - 47 %), and other media (glass spheres, with different fractions of grain sizes and a low phi-range of between 10 - 30 %) are exposed to nondirectional flow, tau responds negatively to phi. Empirical equations linking tau and phi, with medium to high coefficients of correlation, were obtained. The dependence of tau on phi is governed greatly by the direction of flow because of the orientation, mineralogy, and mode of packing of the grains and nonuniformity in the size and shape of the grains and pores.Tortuosity tau is defined as the square of the ratio, phi-range of the effective length of pore channels to the length parallel to the overall direction of the pore channels in a porous medium. It has significance in interpreting the hydraulic and electric proper ties of porous media. In this study, experimental results of tortuosity and porosity phi were investigated in relation to different directions of flow in various unconsolidated porous media. When the media (mica, textile fibers, kaolinite, and bituminous soil, with a high phi-range of between 60 - 90 %) are exposed to flow perpendicular to the planes and fibers, tau responds positively to phi. When the media (randomly packed beds of spheres, with a medium phi-range of between 34 - 45 %) are exposed to flow parallel to the planes, tau responds negatively to phi. When the media (glass powders, glass spheres, dry soil, quartz sand, and white sand, with a variety of grain sizes and a medium porosity phi-range of between 37 - 47 %), and other media (g...

Empirical expression of permeability in terms of porosity, specific surface area, and residual water saturation of carbonate rocks

Abstract Using the multi-variable linear regression analysis, the authors developed empirical expressions for permeability in terms of porosity, specific surface area, and irreducible fluid saturation for four carbonate reservoir rock areas in the USSR. The coefficient of correlation varied from 0.981 to 0.997.

Interrelationships among seismic and short-term tectonic activity, oil and gas production, and gas migration to the surface

Abstract Environmental impacts of (1) oil and gas production from hydrocarbon fields, (2) seismic and short-term tectonic activity, and (3) increase in upward gas migration along faults and fractures due to seismic activity are discussed. Natural seismic activity, generally underestimated for platform conditions, may cause disruption of oil and gas production. There is a vast amount of experimental data showing the influence of the processes of petroleum production on local seismic activity and demonstrating that petroleum production may be the cause not only of ground subsidence but may also trigger small- and medium-size earthquakes. In turn, experiments with artificial sources of vibro-seismic energy show that seismic vibrations (artificial or natural) may cause an increase in gas migration to the surface. This means that in seismically active areas, gas leakage at the surface over petroleum reservoirs can present more serious environmental problems, compared to the areas with relatively low seismic activity. Increased hydrocarbon gas migration from the oil and gas fields to the surface can be caused by artificial seismic sources. The authors observed that upon release of artificial energy to the reservoirs, the migration of gases to the surface increases. Additional information for identification of faults that may serve as structural traps for hydrocarbons may be obtained via monitoring short-term tectonic activity in the vicinity of hydrocarbon fields and monitoring of gas concentration anomalies near the earth surface over petroleum fields. The multi-parametermonitoring of tectonic, seismic and geochemical factors in the Tengiz (a very large oilfield in Kazakhstan) gives an important example of the system aimed at monitoring of the potential environmental hazards related to interaction of tectonic and seismic factors with petroleum production.

Chapter 7 Interrelationships Among Surface Area, Permeability, Porosity, Pore Size, and Residual Water Saturation

Publisher Summary This chapter discusses the fundamental relationships for the porous medium of carbonate rocks, both from a pore-size portrait scale and at a macroscopic descriptive scale. There is a reasonable correlation between the porosity and permeability of cores having irreducible (immobile) fluid saturation in the minute pores, crevices, and so on, which do not have a major effect on the flow of fluids through the rock. Several correlations are developed that relate specific surface area of hydrocarbon-bearing reservoir rocks to other petrophysical properties (such as porosity, permeability, and pore size) and residual water saturation. Permeability is one of the most important parameters describing a porous medium, its measurement normally requires a rock sample that is of a suitable size (e.g., 5 cm x 5 cm x 5 cm) and has a simple geometric shape (for example, a cylinder or a cube). Correlations between the permeability and other easier-to-measure quantities, therefore, are discussed extensively both experimentally and theoretically. Several theoretical relationships between tortuosity and porosity have been developed for simplified models, two of which are presented.

Subsidence over producing oil and gas fields, and gas leakage to the surface

Abstract Subsidence over producing oil and gas fields, caused by a reduction of formation fluid pressure and consequent compaction of reservoir rocks, enhances existing fractures and creates new ones. A theoretical prediction of the whole set of associated deformation can not be completely reliable because of physical obscurity and incompleteness of the effective-stress theory and associated models and their inadequacy to describe the three-dimensional processes in a geological environment. Empirically, incompleteness of the overburden weight transmission to the compacting reservoir is obvious from the existence of vertical tensile strain and elongation of formation overlying the reservoir. All this emphasizes the importance of empirical approach. The authors reviewed field observations of subsidence deformations made by many authors.