CHAPTER 9 UNDERGROUND STORAGE OF NATURAL GAS

Transcription

1 CHAPTER 9 UNDERGROUND STORAGE OF NATURAL GAS Underground gas storage may be defined as the storage in reservoirs of porous rock at various depths beneath the surface of the earth of large quantities of natural gas not native to these reservoirs. Before planning storage-field capacity and deliverability, one must have knowledge of the market requirements. The influence of the weather on sales of gas for space heating of buildings is important. When the annual storage volumes and daily delivery rates are developed for a distribution system, the facilities for storage fields may be designed to meet the need. 9.1 THE NEED FOR GAS STORAGE All types of natural gas sales, whether domestic, commercial, industrial, or space heating, present variable load factors. Probably the most difficult load for the distributor to meet is the space-heating load. It varies from a minimum of zero in the summertime to a maximum that can occur any time during the cold winter months. Probably the largest potential market for the natural gas distributor is residential space heating. The problem of the distributor, then, is to find efficient and economical methods of handling the load-factor problem in distribution of space-heating gas. Variation in space heating needs is measured in degree-days, using 65 o F (18.3 o C) mean temperature as the base temperature. A mean temperature of 45 F corresponds to 20 degree-days. For space-heating, Figure 9.1 shows the variation in heating loads for the Detroit area, totaling 6404 degree-days in any one heating season, November through March. 9.2 BASIC CHARACTER OF A STORAGE RESERVOIR A section and a plan view of a reservoir equipped for storage are shown in Figure 9.2. The storage container is a porous solid with a caprock overhead to prevent vertical migration. Water in the storage zone underlies all or part of the gas filled sane or carbonate. Wells designated I/W, for "input and withdrawal", are completed in the storage zone. Observation wells are completed in the water-bearing porous media to permit observation of the pressure and any migrating gas. Depleted gas reservoirs are prime candidates for conversion to storage. The size of the reservoir is determined by calculation from geological data or from the production and reservoir pressures. Such calculations are relatively simple for cases with little or no water movement. The typical injection and withdrawal pattern in storage is shown by Figure 9.3. A delivery system can be installed to cover the market demand for the year, and ideally the unused gas in summer is stored for use in winter. Some flexibility is needed, since variation in weather causes varying demands. Storage fields and pipelines may require some period of reduced load in summer for testing. The storage gas is considered in two parts. The base gas provides for sufficient gas pressure to produce gas adequately at the end of withdrawal. The gas at pressures above the base pressure is termed working gas storage gas and makes up the annual turnover of gas. Figure 9.4 illustrates the pressure-gas quantity relation, showing base gas and working storage. The use of pressures above discovery, a delta pressure, gives added usage for a given container (larger than the discovery gas quantity). This practice has demonstrated large economic benefits to the storage industry for converted gas reservoirs. In gas storage, pressures in the earth may be up to 0.7 psi/ft. There are four key elements in observing ongoing gas storage operations. 1. Monitoring, 2. Inventory verification, 3. Deliverability assurance, and 4. Safety. 102

2 9.2.1 Monitoring Monitoring means more than taking data and making records. It is the analysis of the data that usually detects the early signs of unwanted gas movement. The system under consideration, in addition to the resrvoir, includes 1. Surface piping, 2. Wellbores, 3. Layers of rock above and below the storage zone, and 4. Surrounding area at distance of 1 to 3 miles or more. The reservoir engineer should develop a mental model of the reservoir behavior. Only then the deviations due to unwanted behavior become evident. For example, gas losses through corrosion spots or casing collars can be detected by rising annulus gas pressures, temperature, noise, and neutron logs in wells, or even lower than normal closed wellhead pressures in comparison with neighbors. The challenge is to gather large amounts of data and display them so that the reservoir engineers may see trends and note anomalies that imply that all is not according to the model in mind Inventory Verification The "inventory" is basically a thermodynamic quantity. It relates to the amount of natural gas in storage. Its verification is generally approached by two independent concepts: "volumetric" and "depletion". There are various analytical methods available to the reservoir engineer for verifying the inventories of underground gas storage. The volumetric formulae are sensitive to changes in the variables involved in the equations. Therefore, when calculating the gas content in a heterogeneous reservoir, care must be taken to compensate for the disparity in porosity as it occurs throughout the reservoir. PT b Q = (Gasporevolume)( ) PbTz (9.1) Once the geological information as to the productiveacreage of the reservoir, the thickness of the storage zone the porosity and water saturation is established, the equation evolves to: Q = (Area)(Thickness)(Porosity)( PT b PbTz )(1- s w ) (9.2) By evaluating the original gas in place from the field's production decline curve and knowing the original reservoir pressure and temperature, the gas pore volume could be derived from Equation 9.2. Substituting the resultant volume and the average reservoir pressure and temperature to the same equation, the current storage inventory is determined. In a heterogeneous reservoir, the "bulk-average" method is applied to compensate for the variance in porosity. With the "block-average" method, the porosity-thickness of each well is plotted and contours established mush as you would draw the thickness contours on a isopachous map. Normally, the performance of a storage field is tracked during the injection and withdrawal cycles by evaluation of the hysteresis and deliverability curves. To verify or explain deviations of the reservoir performance patterns as they compare to previous years, the measured inventory should be checked by a volumetric calculation. Verification of inventory by depletion concept is based on the pressure measurements. Closed pressure 103

3 measurements for a period of 3 to 15 days or more are used for all wells, normally when at maximum or minimum storage pressures. For constant pore volume reservoirs, for which the closed pressures are relatively uniform and stabilized, the pressure content data relates the metered production or change in inventory to the initial content, Q1 -Q2 ( P1 Q1 = ) (9.3) ( P1 / z1 )-( P2 / z2 ) z1 where z can be obtained from pressure P, temperature T, and gas gravity G Deliverability Assurance Deliverability is a measure of rate at which gas can be withdrawn from or injected into storage wells. Deliverability relates to unsteady or semisteady state flow of storage gas through porous media. Deliverability is related to inventory and migration because it primarily depends upon the pressure prevailing in the storage horizon. The deliverability is important and essential because of contractual commitment by the companies to supply the markets at times of varying demand. In design, it is the deliverability which establishes the number of wells and the total compression horsepower required. Flow tests on individual wells are obtained as in gas production operations. From gas inventory and/or reservoir pressure measurements plus deliverability data, one can predict the field flow at several stages of the storage cycle. The performance of storage reservoirs becomes less predictable during periods of prolonged high withdrawal rate due to pressure sinks that may develop as a result of heterogeneities. Another problem of continuing interest is interference by water reaching the wellbore. The presence of water not only reduces the permeability to gas but also effectively cuts down the bottom hole pressure drawdown available for gas flow due to increased density of well fluid in the flowing column. Each reservoir and set of wells must be tested to determine which wells will have water intrusion at a given stage of the withdrawal cycle. Deliverability of storage wells after 20, 30, or 40 years of repetitive use may decrease as a result of sandface contamination. The deliverability of wells in Michigan Stray sand reservoirs has declined 4.5 percent per year because of fines, salt precipitation, shale sloughing, and oil residues. early attemps to remove salt gave only a slight increase in deliverability. Recent techniques generally have been successful in increasing deliverability by as much as 426 percent. This was achieved by alternately injecting volumes of (1) xylene, (2) 3% HF/4% HCl, and (3) 2% NH4Cl. There are three components to calculating deliverability from individual well test data 1. the effective permeability of the rock adjacent to the well, 2. the location of the observation well at which the upstream pressure Pf is measured for calculation of the flow, and 3. the position of the stored gas and its ability to travel to the wells. Initially, four point backpressure tests should be conducted individually to obtain the absolute open flow (AOF) for each well. Periodically, one or two point flow tests are in order. Practically, the overall deliverability could be obtained by free flowing all the withdrawing wells for 2-3 days during the peak of the market demand Safety and Risk Risk is the possibility of loss or injury due to an incident in storage operations. Natural gas storage operations have two kinds of risk. The first has to do with the safety of people and property from harm due to explosions or fires resulting from uncontrolled gas losses or movement. The second risk is economic, the possible loss of unretrievable gas underground or into the atmosphere. 104

4 Odorization of Gases-A Safety Measure Natural gases serving as domestic fuel must be odorized so that leaking gas may be detected by its odor. The requirement is that a gas concentration of 20 percent of the lower combustion limit will indicate its presence by smell, a safety factor of 5. This requirement applies to fuel gas in a gas distribution system, but may not apply to high-pressure transcontinental pipelines or distribution lines. Odorants are organic compounds containing sulfur, usually mercaptans, disulfides, thioethers, or carbon sulfur ring compounds. LP gas (propane) is marketed as a liquid, after in cylinders. Here the odorant is placed in the liquid, which in turn gives off a vapor fuel with the proper odorant concentration. 9.3 DETERMINATION OF NONRECOVERABLE GAS The amount of non-recoverable gas is of interest in storage reservoirs since it has to do with the mechanics of storage reservoirs. For non-water drive reservoirs, it is a matter of economics, well flow capacity, and low a rate can use for the utility. Abandonment pressures vary for such gas fields, with pressures like psi often used. The non-recoverable gas content of a field is the gas left at the abandonment pressure. In water drive gas fields or aquifer storage projects, water will flush a portion of the reservoir while gas is being removed below the original aquifer pressure. Such invading water will trap gas at the prevailing pressure. In abandoning a field, it is assumed that gas will be produced from the wells following a withdrawal period. Water from the aquifer will enter the reservoir, interfering with well operation. At some point, it will become noneconomical to continue production of the remaining gas and the reservoir will be abandoned. This does not mean that no more gas can be produced-only that it is not economical or it is impractical to use the field to serve the utility market. At abandonment, the reservoir is divided into three portions (Figure 9.5). The first is the low-pressure gas space at the crest of the reservoir, from which the last gas is withdrawn. This layer must be thick enough to permit gas production from a group of wells without interference by advancing water. The other two parts of the reservoir are the part that has been invaded by water, which has residual gas saturation and the bypassed reservoir sand below the level of advancing waterfront. The calculation of the non-recoverable gas includes these three portions of the reservoir and the gas that has dissolved in water contacted by the gas at any time during operation. The formula used for calculating the non-recoverable gas is Q m =V ab 1 1 +(V max -V ab )(1- S w )(1- F sw ) +(V max -V ab )F sw F r +Q (9.4) s Bg,m Bg,m (1- S w 1 ) B g,ab where Qm = the volume of nonrecoverable gas in standard conditions (scf), Vab = the volume of gas reservoir space not flooded at abandonment (cuft), Sw = connate water saturation, B = the formation volume factor; subscript m denotes condition at the mean reservoir pressure (Pmax + Pab)/2, Vmax = the maximum volume of reservoir space ever containing gas at the maximum pressure Pmax (cuft), Fsw = the sweep factor, fraction of space below gas-water contact at abandonment flushed with water, Fr = the residue gas saturation for water flooded zone, Qs = the gas dissolved in water (cuft). 105

5 The first term on the right-hand side of Equation 9.4 is the gas content (cuft) for the unflooded zone above gaswater contact at abandonment shown in Figure 9.5. The gas content of the nonswept, or bypassed zone below the gas-water contact line is the second term on the right-hand side of Equation 9.4, and the third term represents residue gas content for the swept portion. 9.4 STORAGE IN SALT CAVITIES In 1950 the use of salt cavities for storing propane and butane underground was introduced. Although there had been a long history of creating salt cavities by solution mining of salt, the creation of a salt cavern for the purpose of LP gas storage was an innovation Occurrence of Salt Beds Salt beds occur in two modes within limited areas of the world. These beds may be extensive layers of evaporative or extruded domes of salt. Salt layers in beds are quite different from salt domes. The nature of the beds can be observed in rock-salt mines. Layers of limestone, dolomite, or anhydrite may occur in the salt beds; these do not dissolve in solution mining, but form ledges that fall in as the dissolution progresses. Generally, the NaCl in salt domes is more homogeneous than that in evaporative beds. What protection do salt layers have from percolating streams of aquifer water? On the top of salt beds or domes, there are a series of evaporites including gypsum, dolomite, and anhydrite. Laboratory studies on anhydrite showed that it has an unmeasurable permeability and has were declared a homogeneous rock or super caprock. Anhydrite reacts with water to form gypsum: CaSO4(s)+2 H 2O(l) CaSO4.2 H 2O(s) (9.5) What isolates salt beds in the earth? Salt layers have anhydrite in their caps, and gypsum is present. Gypsum is believed to protect the salt layer from fresh water dissolution. When the edge of salt beds have no anhydrite covering, salt dissolves over geologic time. The conversion of anhydrite to gypsum is an ongoing process that isolates salt from ground waters. What is the nature of the salt bed? The rock has a very low porosity and permeability even after coring. Anhydrite is more stable and has been shown to be essentially a zero porosity rock with zero permeability. It reacts with pure water but not with indigenous brine. Salt layers may have occlusions of liquid brine but otherwise are generally dry. Some salt mines are dusty because of particles given off in the physical handling of salt. Table 9.1 is a brief description of the Huntorf salt cavity for gas storage in Germany. The porosity of rock salt taken from mines is on the order of 0.6 to 2.0 percent. The dry permeability of a specimen with minimum confining pressure varies considerably from practically zero to 100 md. The permeability of salt decreases with time when the specimen is subjected to overburden pressures of 100 to 800 psi. A specimen confined at a minimum pressure had a permeability of 15 md, when it was confined at 800 psi pressure for 17 hours, the permeability was reduced to 0.33 md, and when confined for 500 hours, to 0.13 md. 106

6 9.4.2 Creation of Salt Cavities-Dissolution Table 15. Brief Description of Huntorf Salt Cavity Location Huntorf, Germany Completion 1975 Number of caverns 4 Purpose of storage Peak shaving (seasonal) Type of formation Dome Geologic age Permian Cavern temperature 35 C Total spatial volume m 3 Total storage capacity m 3 Total working gas m 3 Total cushing gas m 3 Withdrawal rate m 3 Maximum design pressure 100 bar Minimum design pressure 25 bar Depth to top of cavern 650 m Maximum diameter 65 m Height 200 m Percent insolubles 5% Depth to salt formation 500 m Last cemented casing depth 650 m Creation of a salt cavity requires not only a main well for injecting water into the cavity, but also a source of fresh water and a brine disposal system, often rock layers of high permeability containing brackish water. The time of dissolution is predictable; it depends upon the water injection rate. Cavern development on a site located by cores drilling or other data involves drilling the well through which fluid enter and leave the cavity (Figure 9.6). Using normal surface casing for potable water protection, the main casing size is determined by the size of the cavern. When drilling into salt, mud with saturated brine gives protection from further dissolution of salt while the hole is drilled to the bottom of the proposed cavern. Fracturing of salt is to be avoided for storage projects. The direct leaching flow system involves pumping fresh water down the inner tube of the well to the bottom of the drilled hole. The brine, after dissolution, comes up the annulus between the fresh water tube and the casing. For reversed leaching the fresh water is introduced in mid chamber from an annulus, with brine exiting through the inner tube (Figure 9.7). Experiences show that using various positions of the water supply and exit can control the brine concentration and the shape of the cavern. Sonar caliper tools (Figure 9.8) are used to obtain the wall distances at various levels. Figure 9.9 gives the four quadrants of measurements on a gas storage cavern Stability of Cavities Cavity stability is the extent to which an acceptable amount of cavity storage volume can be utilized and economically maintained over the planned life of a facility. There are three possible cavity instability cases: 1. Creeping closure caused by anomalies or by the stress around the cavity may rapidly reduce cavity volume to a space inadequate for storage purposes. 2. Roof falls, wall slabbing. 107

7 3. Cycling loading effects, i.e., fatigue, may cause the rock salt to behave as a brittle material after a certain time period. Salt has a degree of plasticity, and thus it can be extruded. It is more mobile at higher temperatures under a given stress. At greater depths there are higher temperatures, and therefore more creep. However, a certain depth is needed to permit a desired pressure to be no more than 0.8 of overburden pressure. A cavity at Eminence, Alabama, closed 50 percent within two years when a lower pressure (3800 psia to 1200 psia) was employed in gas storage Operating Configurations There are two possible operating configurations compensated and uncompensated systems (Figures 9.10 and 9.11). The cost of developing the compensated system is higher than that for an uncompensated system. On the other hand, in order to prolong the life of a salt cavity, higher-pressure operations are desirable and for high pressures, the brine compensated system has advantages. Uncompensated salt caverns depend upon gas pressure changes in the cavern as would occur in gas storage, and this depends on the ability of the cavern salt structure to resist salt creep. Figure 9.10 is a sketch of a brine compensated storage cavity in which a brine head displaces the hydrocarbon withdrawal. This mode is used for propane-butane-natural gas liquid storage. When gas injected into salt cavity, the temperature of the gas in the cavity will rise before it is cooled by the surroundings. On the other hand, temperature decreases during the withdrawal of the gas. Figure 9.1 Degree-days for Detroit area. 108

8 Figure 9.2 Schematic section and plan of a gas storage field. 109

9 Figure 9.3 Typical gas injection and gas withdrawal schedule for storage reservoirs. Figure 9.4 P/z versus gas content for hypothetical gas reservoir. 110

10 Figure 9.5 Illustration of non-recoverable gas in reservoir. Figure 9.6 Leaching to create salt cavities. 111

11 Figure 9.7 Leaching mechanisms; a) direct, b) reverse leaching. Figure 9.8 Schematic drawing of sonar caliper survey. 112

12 Figure 9.9 Sonar measurements on a gas storage cavern. 113

13 Figure 9.10 Sketch of a simple compensated brine/propane system. Figure 9.11 Sketch of a simple uncompensated propane system. 114