Low-Permeability Gas Sands
- Hossein Kazemi (Marathon Oil Co.)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- October 1982
- Document Type
- Journal Paper
- 2,229 - 2,232
- 1982. Society of Petroleum Engineers
- 4.6 Natural Gas, 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 4.2 Pipelines, Flowlines and Risers, 5.6.4 Drillstem/Well Testing, 5.5 Reservoir Simulation, 2.5.1 Fracture design and containment, 1.8 Formation Damage, 4.3.1 Hydrates, 5.9.1 Gas Hydrates, 5.8.3 Coal Seam Gas, 5.6.3 Pressure Transient Testing, 5.8.1 Tight Gas, 3 Production and Well Operations, 5.8.2 Shale Gas, 2.5.2 Fracturing Materials (Fluids, Proppant)
- 1 in the last 30 days
- 686 since 2007
- Show more detail
- View rights & permissions
|SPE Member Price:||USD 10.00|
|SPE Non-Member Price:||USD 30.00|
Distinguished Author Series articles are general, descriptiverepresentations that summarize the state of the art in an area of technology bydescribing recent developments for readers who are not specialists in thetopics discussed. Written by individuals recognized as experts in the area,these articles provide key references to more definitive work and presentspecific details only to illustrate the technology. Purpose: to informthe general readership of recent advances in various areas of petroleumengineering.
Introduction. Low-permeability or tight-gas reservoirs are gas-bearingformations with gas permeabilities of less than 1 md and as low as 1 mu d. Gasfrom reservoirs with gas permeabilities greater than 1 md is known asconventional gas. Gas from low-permeability reservoirs, coal seams, Devonianshale, and geopressured brines is known as unconventional gas. From aprice-incentive point of view, a regulation pursuant to the Natural Gas PolicyAct of 1978 pursuant to the Natural Gas Policy Act of 1978 requires that theestimated average in-situ gas permeability be 0.1 md or less to qualify the gasfrom permeability be 0.1 md or less to qualify the gas from a gas-bearingformation as tight gas. A U.S. Federal Power Commission study in 1973,supplemented by the USGS and a second study by Lewin and Assocs. Inc. in 1978,provided the first publicized estimates of tight-gas reserves in severalpublicized estimates of tight-gas reserves in several well-known basins in thelower 48 states. A more comprehensive study by the Natl. Petroleum Council(NPC) followed in 1980 and later was summarized by Baker. The industry has beenexploring and producing gas from tight-gas basins for nearly 30 years. It wasthe private sector that developed the basic stimulation private sector thatdeveloped the basic stimulation technology to enhance gas production from suchbasins. To accelerate development of domestic gas resources, the U.S. DOEinitiated the Western Gas Sands Project in 1977. This project has broughtgovernment and industry closer in a common cause. In addition to the periodicgovernmental reports (exemplified by Ref. 6), SPE and DOE have been conductingjoint annual meetings to disseminate the technology. The proceedings of thesesymposia are excellent reference sources. A recent book, Unconventional NaturalGas, also presents a clear picture of various technologies related to tightgas, picture of various technologies related to tight gas, coal-seam gas,Devonian-shale gas. and geopressured gas. The gas from gas hydrates (discussedby Holder et al.) is very unlikely to contribute much to the recoverablereserves. The magnitude of recoverable reserves from tight-gas deposits is afunction of two factors: (1) price and other favorable economic incentives, and(2) advances in stimulation technology. The first factor is easier to achievethan the second. In fact, recent government incentives have stimulated drillingin tight gas sands. Although stimulation technology has improvedconsiderably-specifically, massive hydraulic fracturing (MHF) technology-it isvery far from the desired target. As it stands, proper placement andcontainment of fractures during MHF cannot be controlled or predicted withadequate certainty. Properly placed fractures should improve recoveriesProperly placed fractures should improve recoveries substantially. This is whythe placement of vertical fractures to form a well-defined flow network is afundamental concept in NPC's "advanced technology" scenario. Once a fracture iscreated, its properties can be estimated from well-designed pressure drawdownand buildup tests. Normally, these tests must last much longer than those inconventional gas reservoirs. These pressure transient tests often are difficultto interpret by conventional hand calculation. In the past several years,numerical simulators for interpreting such tests have played a significantrole. The procedure is to match the prefracture and postfracture procedure isto match the prefracture and postfracture pressure transient data (drawdown andbuildup tests) pressure transient data (drawdown and buildup tests) with asimulator, then to use the simulator to predict the well's future performance.Recently, attempts have been made to develop a new class of simulators thatsimulate the creation of a fracture using rock mechanics and fluid flowprinciples. The same simulators also are used to principles. The samesimulators also are used to simulate producing the reservoir through thecreated fracture. This kind of technology is in its infancy but certainly addsa new and important dimension to our understanding of stimulation technology. Ihave presented an overview of the present state of the technology. In whatfollows, I attempt to shed additional light on pertinent details.
The Resource Base. The NPC report identifies 113 natural-gas basins in thelower 48 states.
|File Size||306 KB||Number of Pages||4|