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Tight gas is the term commonly used to refer to low permeability reservoirs that produce mainly dry natural gas. Many of the low permeability reservoirs that have been developed in the past are sandstone, but significant quantities of gas are also produced from low permeability carbonates, shales, and coal seams. Production of gas from coal seams is covered in a separate chapter in this handbook. In this chapter, production of gas from tight sandstones is the predominant theme. However, much of the same technology applies to tight carbonate and to gas shale reservoirs.
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- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.69)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.68)
- North America > United States > Texas > Travis Peak Formation (0.99)
- North America > United States > Texas > East Texas Salt Basin > Whelan Lease > Waskom Field > Lowe Paluxy Formation (0.99)
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Tight gas reservoirs generate many difficult problems for geologists, engineers, and managers. Cumulative gas recovery (thus income) per well is limited because of low gas flow rates and low recovery efficiencies when compared to most high permeability wells. To make a marginal well into a commercial well, the engineer must increase the recovery efficiency by using optimal completion techniques and decrease the costs required to drill, complete, stimulate, and operate a tight gas well. To minimize the costs of drilling and completion, many managers want to reduce the amount of money spent to log wells and totally eliminate money spent on extras such aswell testing. However, in these low-permeability layered systems, the engineers and geologists often need more data than is required to analyze high permeability reservoirs.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.48)
- North America > United States > Texas > Travis Peak Formation (0.99)
- North America > United States > Texas > East Texas Salt Basin > Whelan Lease > Waskom Field > Lowe Paluxy Formation (0.99)
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Summary. Relationships of permeability to porosity are shown from analysesof more than 2,100 core plugs from nine wells in the Travis Peak, alow-permeability, tight-gas sandstone formation in northeast Texas. Effects ofreservoir vs. ambient stress are shown for permeability, porosity, and the Klinkenberg factor. The relationship, of brine porosity, and the Klinkenbergfactor. The relationship, of brine permeability to gas permeability is alsoshown. permeability to gas permeability is also shown. Introduction In a cooperative effort, the Gas Research Inst. (GRI) and various industrypartners collected core and log data from nine wells to form an extensive database from which important correlations of porosity and permeability at bothambient and net overburden porosity and permeability at both ambient and netoverburden pressures have been developed for the Travis Peak formation. Routinepressures have been developed for the Travis Peak formation. Routine andspecial analyses were performed on more than 2,100 core plugs taken from 2,093ft of core from these wells. Fig. 1 shows the locations of the nine wells; thetwo outlined areas show where the major activity was focused. Travis Peak is asand-rich Lower Cretaceous formation with environments that include afluvial/deltaic section of low-energy flood-plain mudstones and siltstones, high-energy crevasse splays and main channel sandstones, and amarine-influenced environment with tidal flat mudstones and channel sands. Coring intervals were selected to provide data representative of all thesedifferent depositional environments. Table 1 lists the cored intervals anddepths for each well. A major factor in developing representative core analysisresults is the importance of simulating in-situ reservoir conditions for theporosity and permeability measurements. The effect of reservoir porosity andpermeability measurements. The effect of reservoir (called net overburden here)stress on permeability and porosity is particularly important forlow-permeability rocks. This has been the subject of many studies but, in most, only a few cores were involved from any particular formation or rock type. Mostof the routine analyses in this study include measurements made at both ambientand net overburden stress. As a result, these data constitute the mostextensive data base of this kind for a specific low-permeability formation. Thecore analyses were performed by four different service laboratories, and insome cases companion samples were tested by two different laboratories. Threedifferent methods were used to conduct routine ambient-porosity measurements onselected plugs. Porosities were obtained on the dry, extracted cores by use ofhelium and by saturating the core plugs with toluene and then brine. Thepurpose of these comparisons is to determine whether the porosity of the TravisPeak formation is influenced by the presence of brine and whether heliumporosities match those measured by saturation with a nonreactive porositiesmatch those measured by saturation with a nonreactive liquid. Next, ambienthelium porosity is compared with that measured at either 800 psi or netoverburden stress to determine the effect of stress on porosity. To address theeffect of stress on gas permeability, correlations are shown of Klinkenberg-corrected gas permeabilities, k, measured at near-ambientcondition and at net overburden stress. These correlations are greatly improvedafter cores with either induced or natural fractures are omitted. Correlationsare also presented for the Klinkenberg factor that are somewhat different fromthose previously presented in the literature and that are also improved afterpreviously presented in the literature and that are also improved after thefractured cores are omitted. Further, a correlation that relates brinepermeability to k is presented and compared with previously publishedliterature. previously published literature. For reservoir description andengineering applications, it is important to relate permeability to some rockproperty measurable from logs, such as porosity. Correlations are presented forthe Travis Peak formation relating k to porosity, both measured at net Peakformation relating k to porosity, both measured at net overburden stress. Thesecorrelations are greatly improved when fractured cores are omitted and furtherimproved when derived for specific environmental rock types. Ambient-Porosity Measurements A common method of measuring core porosity is to measure the grain volume byuse of helium and the bulk volume by immersion in mercury. This method isreliable when carefully performed and was used for most of the ambientporosities measured in this study. A second method is to determine the porosityby saturating the core with brine. This porosity could differ if the rock hasreactive clays. A third method is to determine the porosity by saturation withtoluene, which should not react with the rock. All the above methods were usedon a set of 41 core plugs from Well Howell No. 5. Fig. 2 compares porositiesmeasured by on with 15 % NaCl brine and with helium, with thebest-fit-reduced-major-axis (RMA) line as shown. Generally, the brine porosityis 0.25 porosity units less than the helium porosity. Fig. 3 comparesporosities measured with toluene and with helium again, with the best-fit RMAline as shown. The toluene porosity is generally about 0.6 porosity units lessthan the helium porosity, with the difference greater at low porosities. Incomplete liquid saturation of the low-porosity, porosities. Incomplete liquidsaturation of the low-porosity, low-permeability cores may be a factor, although extra care was used in this step. Our conclusion is that, because thehelium and brine porosities are essentially in agreement, porosities measuredwith porosities are essentially in agreement, porosities measured with heliumshould be reliable. Thus, for the overall data base, porosities were routinelymeasured with helium in dry, extracted cores. porosities were routinelymeasured with helium in dry, extracted cores. Porosity Measured at 800-psi Stress Porosity Measured at 800-psi Stress Among the four different servicelaboratories used for the routine core analyses, one had automated equipmentfor measuring porosity and permeability at net overburden stress on two studywells, Wells Howell No. 5 and SFE No. 2. In this system, the base routineporosity of each core was determined by measuring the PV with helium porosityof each core was determined by measuring the PV with helium while the core wasconfined in a core holder at 800-psi sleeve pressure. On the basis of sleevestiffness and conformance, the pressure. On the basis of sleeve stiffness andconformance, the porosities measured in this manner were reported to matchporosities porosities measured in this manner were reported to match porositiesmeasured at ambient (or unstressed) conditions. Fig. 4 compares porositiesmeasured with helium on 176 dry cores at ambient conditions with porositiesmeasured with helium at 800-psi sleeve pressure for Wells Howell No. 5 and SFENo. 2. Data are included only for those cores that were free of induced ornatural fractures. The best-fit RMA line shows a good match for low porosities(less than 5%). In the higher range, porosity is reduced about porosities (lessthan 5%). In the higher range, porosity is reduced about 1 porosity unit whengoing from ambient to 800-psi sleeve pressure. Evidence therefore suggests thata significant reduction in porosity my occur for these cores when confined by800-psi sleeve pressure in this particular system compared with ambientporosity. particular system compared with ambient porosity. SPEFE P. 310
- Geology > Sedimentary Geology > Depositional Environment (1.00)
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- North America > United States > Texas > Travis Peak Formation (0.99)
- North America > United States > Texas > East Texas Salt Basin > Whelan Lease > Waskom Field > Lowe Paluxy Formation (0.99)
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In making the petrophysical calculations of lithology, net pay, porosity, water saturation, and permeability at the reservoir level, the development of a complete petrophysical database is the critical first step. This section describes the requirements for creating such a database before making any of these calculations. The topic is divided into four parts: inventory of existing petrophysical data; evaluation of the quality of existing data; conditioning the data for reservoir parameter calculations; and acquisition of additional petrophysical data, where needed. The overall goal of developing the petrophysical database is to use as much valid data as possible to develop the best standard from which to make the calculations of the petrophysical parameters. Inventory of Existing Petrophysical Data To start the petrophysical calculations, the data that have been gathered previously from various wellbores throughout the reservoir must be identified, organized, and put into electronic form for future calculations.
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Distinguished Author Series articles are general, descriptive representations that summarize the state of the art in an area of technology by describing recent developments for readers who are not specialists in the topics discussed. Written by individuals recognized as experts in the area, these articles provide key references to more definitive work and present specific details only to illustrate the technology. Purpose: to inform the general readership of recent advances in various areas of petroleum engineering. Introduction Tight gas is the term commonly used to refer to low-permeability reservoirs that produce mainly dry natural gas. Many of the low-permeability reservoirs developed in the past are sandstone, but significant quantities of gas also are produced from low-permeability carbonates, shales, and coal seams. In this paper, production of gas from tight sandstones is the predominant theme. However, much of the same technology applies to tight-carbonate and gas-shale reservoirs. In general, a vertical well drilled and completed in a tight gas reservoir must be successfully stimulated to produce at commercial gas-flow rates and produce commercial gas volumes. Normally, a large hydraulic-fracture treatment is required to produce gas economically. In some naturally fractured tight gas reservoirs, horizontal wells can be drilled, but these wells also need to be stimulated. To optimize development of a tight gas reservoir, a team of geoscientists and engineers must optimize the number and locations of wells to be drilled, as well as the drilling and completion procedures for each well. Often, more data and more engineering manpower are required to understand and develop tight gas reservoirs than are required for higher-permeability conventional reservoirs. On an individual-well basis, a well in a tight gas reservoir will produce less gas over a longer period of time than one expects from a well completed in a higher-permeability conventional reservoir. As such, many more wells (closer well spacing) must be drilled in a tight gas reservoir to recover a large percentage of the original gas in place compared with a conventional reservoir. Definition of Tight Gas Reservoir In the 1970s, the U.S. government decided that the definition of a tight gas reservoir is one in which the expected value of permeability to gas flow would be less than 0.1 md. This definition was a political definition that has been used to determine which wells would receive federal and/or state tax credits for producing gas from tight reservoirs. Actually, the definition of a tight gas reservoir is a function of many physical and economic factors. The physical factors are related by Darcy's law, as shown in the stabilized, radial-flow equation, Eq. 1, (Lee 1982).
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- North America > United States > Texas > Travis Peak Formation (0.99)
- North America > United States > Texas > East Texas Salt Basin > Cotton Valley Group Formation (0.99)
- North America > United States > Texas > Anadarko Basin > Cleveland Formation (0.99)
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