Initial Gas In Place Research Articles

Kaybob South - Reservoir Simulation of a Gas Cycling Project with Bottom Water Drive

As with all numerical simulations, the reliability of the output can be no better than the validity of the input. But here is an example of how simulation with meager data can be justified for the range of performance possibilities that it does show. possibilities that it does show. Introduction The Kaybob South field is located approximately 160 miles northwest of Edmonton, Alta., Canada (see Fig. 1). The Beaverhill Lake ‘A’ pool was discovered in 1961 on the southwestern side of the Beaverhill Lake basin. This basin is the scene of sizable oil accumulations such as Swan Hills, Judy Creek, Virginia Hills and Kaybob, but Kaybob South is the first instance of substantial sour gas production. The Kaybob South Beaverhill Lake ‘A’ pool is, in fact, one of the largest gas reservoirs in Canada. The reservoir is at a depth of 10,500 ft and is totally underlaid by water. It currently encompasses some 57,000 acres, has an elongated shape, and extends on trend with the regional strike for about 32 miles. The pool's initial gas in place may be as much as 4,000 Bcf. Because of the possibility of significant retrograde liquid losses upon depletion, it was essential to choose a method of exploiting the pool early in its development. Reservoir simulation to design the cycling project for Unit No. 1 was carried out in three phases. The first phase, involving a reservoir volume of 363 Bcf, produced the basic injection pattern and investigated produced the basic injection pattern and investigated the effects of production rate. The second phase updated pattern studies and included several voidage replacement ratios. The final simulation in Nov., 1968, confirmed the suitability of the scheme with a revised reservoir interpretation and included a study of specialized problems. This paper presents the results as applied to the latest reservoir data. Development History Gas was discovered in the Beaverhill Lake formation in 1961. The follow-up exploratory well revealed the Beaverhill Lake to be water bearing. Over the next 5 years, with mediocre success, four additional wells were drilled to the Beaverhill Lake. Significant Beaverhill Lake stepouts were made in early 1967 with the drilling of two more wells, and the estimate of initial gas in place expanded from 363 to 782 Bcf. A lull in exploration followed, during which the initial planning of a depletion mechanism was formulated. It was apparent that the pool was large enough to support a cycling scheme, and that pressure maintenance would result in a notable increase in recovery of LPG, condensate and sulfur. The planning and designing of the cycling project began in 1967 without full delineation of the reservoir limits. At the start of 1968, three wildcat wells were completed and the proved limit of the pool was extended some 10 miles to the southeast. Subsequent drilling at a brisk pace through 1968 revealed that the pool existed over a distance of 32 miles. The reservoir thickened and broadened to the southeast so much that the cycling scheme under development was hopelessly inadequate for efficient economic depletion of the entire pool. However, the design remained applicable to the earlier pool area. P. 481

Rock Compressibility and Failure as Reservoir Mechanisms in Geopressured Gas Reservoirs

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

Determining and Averaging Gas Reservoir Pressures

The results of this study indicate that the nearest fit to a linear gas material balance plot (the best estimate of initial gas in place) is obtained by correcting the estimated average well pressure for asymmetrical drainage effects, then weighting the individual average pressures by the pore volume drained by each well. A significant error may result in the estimated gas in place if geometric effects or asymmetrical drainage for the individual wells is not considered. This study is confined to one of the major Wilcox gas condensate sandstone reservoirs under the Sheridan field, Colorado County, Tex. Production is from 29 irregularly spaced wells located in the central two-thirds of the reservoir. The last one-fourth of the production period under consideration was influenced production period under consideration was influenced by transient drainage effects. Production acceleration caused a sustained period of transient pressure behavior that resulted in an erratic plot of the ratio of average pressure/gas deviation (P/Z) vs cumulative production. By contrast, the gas material balance curve should be linear for a volumetric reservoir and should not be affected by transient flow if average reservoir pressure can be determined accurately. The pressures used to prepare this performance curve were based on radial flow assumptions and rate weighting techniques. Similar material balance curves were prepared by estimating the pore volume and area for each well from the linear or semisteady-state portions of pressure-time plots. These data resulted in three pressure-time plots. These data resulted in threeadditional P/Z plots: geometrically corrected; pressure weighted by both Pore volume and production rates; and a pore volume weighted pressure based on radial drainage. Three indicators were used to measure the effectiveness of the four techniques: the magnitude of the standard deviation; a comparison of the extrapolated and actual initial pressure; and the shape of the performance curve in the anomalous region. The first performance curve in the anomalous region. The first two of these indicators are presented in Table 1 and the third is illustrated graphically in Fig. 1. It is apparent that volumetrically weighting the individual average well pressures is superior to rate weighting for either method of determining average pressure. This is to be expected since wells draining pressure. This is to be expected since wells draining this reservoir have different rates of pressure decline due to variable extent of formation damage and asymmetrical well drainage geometry. In addition, it is clear that smaller standard deviations result if the effects of asymmetrical (non-radial) drainage are considered. P. 249

Determination of Natural Gas Recovery Factors

Abstract Theoretical and statistical methods of determining recovery factors ofsolution, associated and non-associated natural gas, including gas condensate, are presented as a set of practical tools. The effects of recovery mechanisms and pool and gas-well performance on gasrecovery are examined for conditions applying to constant volume, water drive, gravity segregation and secondary recovery. Ways of recognizing such cases areindicated. The supporting techniques comprise material balance calculations, performance predictions and statistical analyses of depleted pool and predictedrecovery data. In material balance calculations, the gas recovery is consideredin terms of either:initial gas in place multiplied by a recovery factor orinitial gas in place less the gas remaining at abandonment. Performance predictions are based on geological, engineering and economic factors. The background study dealt with explicit correlations between:recovery factor, abandonment pressure or related expressions and pool depth, pay thickness, initial reservoir pressure, flow capacity and size of gas accumulation; andequivalent residual gas saturation and formation water saturation, porosity, permeability and specific surface area. The format for several correlationspresented is predetermined by theoretical considerations. Existing short-cutmethods are also evaluated. Easy-to-use approximations readily yield reliableestimations despite their simplicity and can be of considerable significance;however, the practicing engineer is urged to recognize and understand their limitations. An extensive review of methods of determining recovery and an analysis ofmany evaluations by industry form the foundation for the recommended guidelinesto serve the engineer. The methods of determining recovery factors areconsidered according to their practicality; i.e. the availability ofdata and the complexity of implementation. Useful relationships are classified, important steps of the proposed procedures are outlined and severalapplications are illustrated.

The Importance of Water Influx in Gas Reservoirs

Abstract Although it has long been realized that gas recovery from a water-drive gas reservoir may be poor because of high residual saturations under water drive, it appears that only limited information on the subject has been available until recently. This study was performed to show the quantitative potential importance of water influx. Results indicate that gas recovery may be very low in some cases: perhaps as low as 45 per cent of the initial gas in place. Gas recovery under water drive appears to depend in an important way on:the production rate and manner of production;the residual gas saturation;aquifer properties; andthe volumetric displacement efficiency of water invading the gas reservoir. The manner of estimating water-drive gas reservoir recovery can vary considerably. Examples are: the steady-state method, the Hurst modified steady-state method, and various unsteady-state methods such as those of van Everdingen-Hurst, Hurst, and Carter-Tracy. The Carter-Tracy water influx expression was used in this study. In certain cases, it appears that gas recovery can be increased significantly by controlling the production rate and manner of production. For this reason, the potential importance of water influx in particular gas reservoirs should be investigated early to permit adequate planning to optimize the gas reserves. Introduction In recent years, the economic importance of natural gas production has become increasingly apparent. This has been evidenced by more intensive exploration efforts aimed at gas production, and exploitation of both deep, as well as low-permeability gas reservoirs. Technical developments such as deep-penetration fracturing have made development of such formations economically feasible. Unfortunately, water influx has forced abandonment of a number of gas reservoirs at extraordinarily high pressures. Although reservoir engineering methods for estimating water influx have long been available, it appears that application of these methods to the water-drive gas reservoir has been sporadic.1–3 Available methods for estimating water influx which can be applied to the water-drive gas reservoir problem include the steady-state method,4 the Hurst modified steady-state method,5 and various unsteady-state methods such as those of van Everdingen-Hurst,6 Hurst,7 and Carter-Tracy.8 Interesting applications of these solutions to gas reservoir and the aquifer gas-storage problems have appeared recently.3,12,18 The experimental study of residual gas saturations under water drive by Geffen et al. in 1952 indicated that residual gas saturations could be extremely high.9 A value of 35 per cent of pore volume is often used in field practice when specific information is not available. The study of Geffen et al. showed that residual gas saturation might be much higher in some cases. Naar and Henderson concluded that the residual non-wetting phase saturation under imbibition should be about half of the initial non-wetting phase saturation.10 The Naar and Henderson result that residual gas saturation under water influx should be about half the original gas saturation is recommended as an estimate if laboratory measurements are not available. Thus, it is clear that a considerable portion of the initial gas in place might be trapped in a water-drive gas reservoir as residual gas at high pressure. A full water-drive would result in loss of residual gas trapped at initial reservoir pressure. Consideration of transient aquifer behavior leads to the conclusion that high-rate production of water-drive gas reservoirs could result in improved gas recovery by reduction of the abandonment pressure. However, there appears to be little quantitative information on this possibility. One of the few advantages of water-drive, gas production appears to be improved deliverability through water-drive support of the reservoir pressure. There may also be an advantage in higher condensate recovery caused by pressure maintenance for gas-condensate water-drive reservoirs. In view of the preceding, this study was made to assess the potential importance of water-drive in gas reservoir engineering. The Carter-Tracy approximate water-influx expression was used because this equation offers some advantages in hand-calculation which do not appear to have been generally recognized.8 However, calculations were performed in the main with a high-speed digital computer to permit evaluation of the effect of water-drive under a large variety of conditions.

The Medicine Hat Gas Field

Abstract This paper discusses the development and performance of Canada's largest individual accumulation of gas. The proven initial gas in place is in excess of 2 trillion cubic feet. The first well was drilled in the Medicine Hat sand in 1904, although gaswas known to be present in the area in the 1890's. During the first 50 years, development was very slow, as there was only a small localized market, and onlyabout 100 wells were drilled. The approval of gas export from Alberta during the 1950's provided the incentive to completely develop the pool. Subsequent approval for export from the Medicine Hat field led to the drilling of about300 wells between 1958 and 1963. The field now contains about 400 wells, and development is by no means complete. The producing horizon is a shallow, thin, shaly sand. The determination of effective pay is complicated by the presence of extremely fine layering of the shale and sand. A correlation between logs and core analyses was developed in1959 following an intensive geological study of the cores. Further drilling andthe observation of field performance has proved this correlation to be satisfactory. The uneven development of the pool over a period of 60 years has causedconsiderable gas migration into the older producing area. Engineering studies involving the application of fluid flow principles showed that the gas reserves of many operators who were denied access to the local market were being seriously depleted by drainage. These findings were presented to the Alberta Oil and Gas Conservation Board and may have been a factor in the subsequent granting of export permits for several operators. Methods of calculating the drainage across lease lines are described. Recent engineering studies have shown that gas drainage is, in many instances, being curtailed. The previously penalized operators are now participating in their rightful share of gas from this field. It is now morethan ever an important asset to the economy of southeast Alberta.