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A study of the North Ossun field, Louisiana, reveals that as reservoir pressure is depleted the increase in net overburden pressure initially pressure is depleted the increase in net overburden pressure initially causes rock failure and as the failure continues with decreasing pore pressure, rock compressibility decreases until eventually it reaches a pressure, rock compressibility decreases until eventually it reaches a normal value. Introduction Rock compressibility has long been recognized as an important factor in material balance calculations of oil in place for closed reservoirs producing above bubble-point pressure. For example, if the pore volume compressibility of the reservoir rock is half of the compressibility of the undersaturated oil, neglect of the rock compressibility term results in about a 50 percent overestimation of oil in place. In general, it percent overestimation of oil in place. In general, it may be stated that in material balance calculations on closed reservoirs, consideration of rock compressibility becomes increasingly important as the fluid compressibility decreases. For this reason the effect of rock compressibility is commonly neglected in studies on gas reservoirs where gas compressibility is usually great. Because gas compressibilities decrease with increasing pressures, the consideration of rock compressibility becomes increasingly important for deeper, high pressure gas reservoirs. For example, the compressibility of the gas in the reservoir to be discussed is 30 microsip** at an initial reservoir pressure of 8,921 psia. For a nominal pore volume rock compressibility of 6 microsip, neglect of rock compressibility in material balance calculations on a closed reservoir will result in a 20 percent overestimation of initial gas in place. If the rock compressibility is larger than 6 microsip, then a still larger over-estimation of gas in place results. In this study we propose that because of low net overburden pressures, rock compressibilities in geopressured reservoirs are considerably greater than for similar rocks in normally pressured reservoirs. We further suggest that as pressured reservoirs. We further suggest that as reservoir pressure is depleted, the increase in net overburden pressure initially causes inelastic rock compaction or rock failure. As failure continues with decreasing pore pressure, rock compressibility decreases and eventually reaches normal values in the range of 6 microsip. North Ossun Field, Louisiana The mechanisms proposed in the previous paragraph are believed to be illustrated by the performance of the NS2B reservoir of the North Ossun field, Lafayette Parish, La. This is a geopressured gas reservoir with an initial pore pressure of 8,921 psia at 12,500 ft subsea depth, or a gradient of 0.725 psi/ft. Table 1 gives pertinent data on this reservoir. Good geologic control is indicated by the structure map, Fig. 1. Although a gas-water contact exists, it is doubtful that the associated aquifer is very large because the reservoir appears to shale out on the west. In addition, considerable complex faulting in the area almost certainly closes the reservoir with a small associated aquifer. Good core and log data have been used to calculate an initial hydrocarbon pore volume of 583 million cu ft, and, with PVT data, to calculate an initial gas in place of 114 Bscf. JPT P. 1528
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.36)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Reserves Evaluation > Estimates of resource in place (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
In the past, when the industry year after year was outdoing itself in drilling and expansion, our petroleum engineering schools turned out adequate numbers of well-trained engineers with the heavy emphasis on the "know-how" of the industry. The future, with its greater uncertainties, is going to require more creative thinking. Petroleum engineering, certainly as it will be practiced even more so in the future, is a very indirect science. We cannot even get in direct contact with the oil and gas in their native reservoirs. We can only deal with indirect readings and conduct operations from the surface of the ground which we hope will have certain effect at depth. Does our present petroleum engineering curriculum adequately recognize this? Curricula Weaknesses First, our mathematics is still generally taught as a mental discipline rather than as a tool. Fortunately, some of our schools are now teaching more finite mathematics. Mathematics taught in our engineering schools should be closely keyed to the realization that our future engineering will be done more and more by computer. Secondly, this business of drilling and producing oil and gas is a risk industry. Theoretical conditions of risk are interwoven in the fields of stochastics and probability; yet, nowhere in the petroleum engineering curricula familiar to this writer is there any required course in probabilities and statistics. Engineers within our organization who have had formal academic training in this field received it at government expense through postgraduate meteorological instruction. There has been too much tendency to "water down" courses from other departments so that the petroleum engineering student can pass them. This has been a problem particularly with regard to physical chemistry and some of the electrical engineering courses. The petroleum engineering curriculum should be one of the toughest in the engineering school. If it is not, the graduate of a petroleum engineering school will find it increasingly difficult to find a job in the oil and gas producing industry. We also have been hoodwinked by some of our own state legislatures into requiring our engineering students to spend a disproportionate number of the very limited semester hours available in the four-year curriculum in the study of high school history and government courses. Caliber of Faculties Let us move on now to a brief review of another point that has a bearing on our subject with regard to the adequacy of present-day petroleum engineering education. This is the problem of the caliber of faculties who teach petroleum engineering. First, we shall review the situation with regard to publications. If you pick up the professional publications of other Founder Engineering Societies, you find that from 80 to 90 per cent of the papers seem to have been written by engineering faculty members. Even in the AIChE publication known as Chemical Engineering Progress, which is primarily an operating journal, nearly half of the published papers come from faculty members. P. 458^
- Personal (0.68)
- Overview (0.48)
- Instructional Material > Course Syllabus & Notes (0.48)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.34)
Horner and van Everdingen have shown that the pressure drop within the wellbore, as a result of having produced the well at a constant rate q for time t, where t is sufficiently large, is: (Equation 1) van Everdingen observed that better agreement between theory and well performance can be obtained if, instead of assuming the permeability is ke everywhere about the well, it is assumed the permeability near the wellbore is substantially reduced as a result of drilling, completion and/or production practices. In order to account for the additional pressure drop he introduced the dimensionless quantity S, the skin effect factor, so that Eq. 1 becomes: (Equation 2) Eq. 2 might have also been obtained as follows. Assume a zone of altered permeability ka exists about the well out to a radius ra, and beyond that the unaltered, external permeability ke. The additional pressure drop required to overcome this skin of reduced permeability may be calculated with sufficient accuracy using the incompressible flow equation; for Brownscombe and Collins have shown almost no difference between compressible and incompressible steady-state flow, in the vicinity of the wellbore, and the small volume of fluid in the vicinity of the wellbore makes unsteady-state mechanics unnecessary. Then, (Equation 3) The sign of this skin pressure drop will be positive or negative depending upon whether the altered permeability ka is smaller or larger, respectively, than the external permeability ke.
Introduction In all types of subsurface pressure gauges the extension which occurs in the pressure-sensitive element is a function of the difference between the external (well or calibration) pressure and the internal pressure within the gauge, rather than a function of the external pressure only. The internal pressure is near atmospheric and depends uponthe quantity of air sealed within the gauge at the time of calibration or measurement, the quantity of moisture (liquid water), if any, sealed within the gauge, and the temperature at which the calibration or well measurement is made. Part of this correction for the change of internal pressure with temperature is taken care of by the customary temperature coefficient of the gauge. However, part of it is not, and while this portion may be only a few psi, it is nevertheless predictable or preventaple, and should be considered in precision measurements. Summary In precision measurements the error introduced by sealing the gauge during a well test at a different temperature and pressure from that of calibration may be corrected for by using the equation presented, or it may be prevented by taking care always to seal the gauge at near calibration conditions. The error introduced by sealing moisture in the gauge may be prevented by taking care to keep moisture out of the gauge, or by removing the moisture by either warming or evacuating the gauge. Both of these errors are independent of the range of pressure measurement and the type of gauge, and are in addition to the usual temperature correction.
Introduction Methods have been developed for drilling (a) slant holes and (b) one or more curved holes from a common central hole in producing formations. These wells will have productivities exceeding that of a single hole drilled normal to and fully penetrating the producing stratum. other factors being equal. This increase is due to the decrease in resistance to flow in the vicinity of the wellbore by an increase in the cross section exposed to flow with increasing footage drilled in the formation and due to the geometrical arrangement of the holes with respect to the drainage radius or boundary. Where other factors are not equal, for example, where zonal damage exists in the single, fully penetrating hole but not in the slant or curved holes, additional increases in productivity will accrue. Many of these wells have been drilled in the past and are currently being drilled with various results reported. While the authors are aware of some of the practical aspects of drilling and completing these multiple. curved holes, it is their hope to provide some basic data on the improvement in productivity to be anticipated in these wells for a number of hole arrangements or patterns. Model Studies Electric analogue or model studies have been used for solving some reservoir fluid flow problems in which the mathematical solutions are unknown, too approximate or too complex. For example, recent studies have used this method to determine the effect of shot density, diameter, and depth of penetration of gun perforations on well productivity. The success of these studies depends upon the analogy between Ohm's Law for electrical flow and Darcy's Law for incompressible fluid flow in homogeneous rock. Where a geometrical scale reduction is desired, a single scale factor is applied to all dimensions.
A Rotational High Pressure Viscosimeter
Hawkins, Murray F. (Louisiana State U.) | Kimmel, Marion L. (Louisiana State U.)
Introduction Sage appears to have been the first (1933) to design a rolling ball viscosimeter for the express purpose of measuring the viscosity of oils with natural gas in solution, i.e., under reservoir conditions. In 1940 Hocott and Buckley further refined the rolling ball instrument in both design and method of operation, and their instrument, known as the Humble type, was the forerunner of present day viscosimeters used in petroleum production and research laboratories. They also initiated the technique of charging the viscosimeter with a sample directly from a bottom hole sampler. In 1948 the committee on engineering research of the Petroleum Division of the AIME in Part 3 (1) of the Physical-Chemical Topics of Table 1 suggested the "development of improved and simpler methods of measuring viscosity of reservoir fluids." This note will describe a rotational, high pressure viscosimeter which has been developed in response to this suggestion but whose relative merits are yet to be determined fully. The Instrument Fig. 1 is a photograph and Fig. 2 is a cross sectional drawing of the instrument. It consists of a non-magnetic, stainless steel rotor about 4 in. in length and 1 in. in diameter centered axially within a non-magnetic, stainless steel, pressure vessel of cylindrical bore. The rotor is mounted on miniature, precision ball bearings and has a radial clearance of about 1/64 in. Alnico magnets are inserted perpendicular to the axis of rotation on either end of the rotor, those at the top to serve as indicator magnets, those at the bottom, as the driven magnets which turn the rotor. A constant (but variable) speed motor outside the pressure vessel turns the rotor by means of a driving magnet attached to the motor shaft. The motor speed is checked using an aircraft type, precision, spring-wound interval timer and an electric impulse counter to record revolutions by means of an electric contactor on the motor shaft.