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Exploration, development, structural geology
Abstract When a continuous sand is bounded by zones of higher, but unequal, minimum in-situ stress, a vertically asymmetric hydraulic fracture results. The modeling is much more difficult than in the symmetric case mainly because the width equation is harder to formulate and solve. In this paper we present the principal components of the modeling, which includes principal components of the modeling, which includes non-Newtonian flow, leakoff with spurt loss, and "storage" of fluid due to volume expansion. The assumption is that the fracture is highly elongated, i.e., stress contrasts between pay and bounding zones are relatively large (>few hundred psi). Vertical gradients of minimum in-situ stress and fluid pressure can be included in the modeling. To illustrate. the results, we present design calculations for a 30,000 gallon fracture, which was the first stimulation in the Multi-Well Experiment. The 80 ft fracture interval in the Paludal zone has at its upper edge a 520 psi stress contrast, and at its lower edge a 1195 psi contrast. Computed fracture height growth above and below the perforated interval, bottomhole pressure, and width perforated interval, bottomhole pressure, and width profiles in vertical sections are displayed. profiles in vertical sections are displayed. Comparison is made with diagnostic measurements of fracture length, height, and bottomhole pressure. Introduction At depths of a few thousand feet or more, induced hydraulic fractures will normally be vertical. Height growth containment is important so that the fracture will reach farther along the payzone, and so that the chance of vertical penetration into, for example, a water-bearing zone will be reduced. Although many factors influence height growth, the most important one appears to be the stress contrast between pay and bounding zones, where by stress we mean minimum in-situ stress. Here we study fracture height growth by developing a model for an expanding hydraulic fracture applicable when the fracture is highly elongated, with length along the payzone much greater than height. However, vertical variations in elastic parameters are not considered. The fracture shape in this paper is self-determined, in contrast to that in which an elliptical shape is chosens and the corresponding height or semi-minor axis determined. A variable-height fracture model has been intensively studied by Cleary and co-workers. The so-called "pseudo-3D" model treats the fluid flow as a dominant ID flow along the payzone, plus an auxiliary ID flow in the vertical direction. Although the models of Nolte and Palmer and Carroll take the vertical flow to be Palmer and Carroll take the vertical flow to be zero, thus simplifying the problem considerably, the general formulations are similar enough to Cleary's to be included under the rubric "pseudo-3D." In all these models, the fracture width is approximated by dividing the fracture into a number of vertical sections, and applying 2D elasticity theory to each vertical "line" crack. Thus the fracture is assumed to be highly elongated with length/height ratio >5. Finally, 3D modeling, with proper 2D fluid flow, is under development, but the problem is formidable and the computer run time enormous. In the interim we can learn much from pseudo-3D models. In general, the bounding layer stresses will not be equal, leading to a fracture which is vertically asymmetric, and furthermore both the minimum in-situ stress and the fluid pressure will vary with depth. This is the principal modification we make to the symmetric model, described previously. Other additions are:spurt loss has been included in the leakoff, non-Newtonian flow is included. An extended model for the symmetric case, which has essentially the same components as herein, is described elsewhere. In that paper, a comparison is made between published results in three pseudo-3D models, some discrepancies are pointed out, and suggestions for reconciling the models are made. In the asymmetric model of this paper, calculation of fracture width is the most difficult task. We give most of the details here. Theoretical calculations of asymmetric fracture shapes have been reported by Settari and Cleary, but they appear to emphasize low stress contrasts (< couple hundred psi). Nolte gives one asymmetric width profile in a vertical section, but no method of calculation, nor any resultant fracture shapes, were given. Finally, to illustrate the results of the asymmetric model, we use the model to predict fracture height, pressure, and width for the first stimulation of the Multi-Well Experiment (MWX) carried out in December 1983. This prediction is compared with available fracture diagnostic measurements. P. 453
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.46)
Abstract Independent oil and gas copies such as Belden and Blake continue to search for new sources of hydrocarbon reserves. In many instances this has resulted in a re-evaluation of reservoirs that were considered depleted or of higher risk. The Trenton Limestone reservoir, located in the northwestern part of Ohio, is a case study of such an occurrence. Through an extensive three-year evaluation of this area, both geologically and from an active drilling program, it was found that the area still contains vast amounts of hydrocarbons located in various types of geologic traps. While large amounts of oil and gas exist in this reservoir, ultimate production is sensitive to well completion and production practices. More specifically in the case of natural gas, pressure transient tests were conducted to pressure transient tests were conducted to determine whether gas reserves were sufficient to consider pipeline construction. Results of the reservoir tests verified the Trenton formation to be of low permeability in the range of one millidarcy, and porosity between 2 and 4 percent. An economic evaluation was then percent. An economic evaluation was then performed to determine what reservoir flow performed to determine what reservoir flow capacities, well spacing and economic criteria were required for successful engineering and economic development. Conclusions of the case study showed (1) the need for high grading the well site selection through geological interpretation in order to and the "sweet spots," (2) a need f or stimulation treatments designed to enhance production, (3) a marginal return on investment production, (3) a marginal return on investment with current economics, and (4) that gas pipeline construction should be delayed until pipeline construction should be delayed until larger reserves are found or until a more favorable gas marketing climate develops. Introduction In 1980, Belden and Blake made a concerted effort to find new sources of oil and gas reserves. This was brought about from the influx of investment dollars in the search of domestic hydrocarbon production. Starting in 1975, Belden and Blake began drilling wells at an ever increasing number each year. Drilling approximately 30 wells per year in 1976 and 1977, they doubled this amount by 1979, and by 1980, were drilling approximately 75 wells per year. with this large increase in well drilling, new developmental and exploratory acreage was actively being acquired to supporting this ever increasing well development program. Northwest Ohio was one of the areas selected to explore for new sources of hydrocarbons. Activity in this part of Ohio was relatively sparse at the time; however, operators such as Pioneer Drilling Company Inc.. were continuing to Pioneer Drilling Company Inc.. were continuing to explore for commercial oil and gas production. The target was those areas in juxtaposition to the Old Trenton Field which produced over 500 million barrels of oil and about 1 trillion cubic feet of gas in the late 1800s and early 1900s. Ail of this production was found at shallow depths of less than 1,500 feet below the surface. Unlike the old reservoir which was a vast, highly prolific oil and gas formation, these new reservoirs appeared as smaller fields and were complex and difficult to delineate. Working with Pioneer Drilling copy Inc., Belden and Blake then began an active drilling program starting in 1980 and continuing through program starting in 1980 and continuing through 1983. During this time 50 wells were drilled in the Northwestern Ohio area. This paper will highlight these field results and illustrate the complex nature of this reservoir with emphasis on the natural gas production and testing program. program. P. 311
- Geology > Mineral (1.00)
- Geology > Geological Subdiscipline (0.94)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.51)
- North America > United States > Texas > Permian Basin > Area Formation (0.99)
- North America > United States > Ohio > Michigan Basin > Lima-Indiana Field (0.99)
- North America > United States > Michigan > Michigan Basin (0.99)
- (14 more...)
Abstract Trends of subsurface structure, total sandstone isopachs and thickness variations are used to geologically characterize the depositional subdivisions of the non-marine part of the Mesaverde Group in the Rulison Field area of the southern Piceance Basin. Investigation of a gas production trend indicates that higher productivity may be controlled by structure induced fracturing productivity may be controlled by structure induced fracturing and is independent of thicker sandstone accumulations. In addition, over-pressured gas reservoirs in a non-marine part of the Mesaverde Group have not been fully evaluated and may be an important exploration target. Introduction Objective. The objective of this investigation is to integrate the geological and production characteristics of the Rulison Field area to obtain a more concise understanding of the factors which allow greater production from low-permeability, lenticular reservoirs present in the non-marine part of the Mesaverde Group. In present in the non-marine part of the Mesaverde Group. In addition, characterization of the subsurface geology and production should improve evaluations of the Department of Energy's MultiWell Experiment (MWX). The area investigated is located in Garfield County, Colorado, and includes the Rulison Field and Mamm Creek Field, hereafter referred to as the Rulison Field area. The study area is shown in Figure 1. Interval Investigated. The sediments characterized in this study are a part of the Mesaverde Group clastic wedge deposited during Late Cretaceous time as a series of delta systems which pregraded into an interior seaway. The base of the interval investigated is the top of the Rollins Sandstone Member of the Mesaverde Group. The top of the interval investigated is the top of the Ohio Creek Conglomerate (the top member of the Mesaverde Group). A generalized stratigraphic column, shown in Figure 2, illustrates a portion of the geologic section present in the southern Piceance portion of the geologic section present in the southern Piceance Basin. Methods. Data for this study includes logs from 44 wells with penetrations into the Mesaverde Group. Monthly production penetrations into the Mesaverde Group. Monthly production records for 29 of these wells were also acquired. A total sandstone isopach map was prepared which utilizes gamma ray logs run through the non-marine Mesaverde section to identify sandstone units. Sandstones were differentiated from siltstones and mudstones so the isopach map represents only the total thickness of relatively cleaner sandstone. Included in the isopach map were sandstone units having a gamma ray deflection less than 25 percent of the difference between the maximum and minimum gamma ray deflections in the non-marine Mesaverde section. The total thickness of cleaner sandstone per well was plotted on a base map and interpretively contoured. plotted on a base map and interpretively contoured. Coal units were identified in this investigation by interpreting responses from a combination of caliper, gamma ray, resistivity, density or neutron logs. MWX. Much of the regional geological data in the Rulison Field area has been made available through studies performed in association with the Multi-Well Experiment. MWX is a coordinated research effort to investigate means of stimulating production of natural gas from low-permeability, lenticular sandstone reservoirs. The MWX site, consisting of three closely spaced wells (MWX-1, MWX-2 and MWX-3) penetrating the non-marine Mesaverde section, is located in Section 34, T6S, R94W. STRUCTURE AND TOTAL INTERVAL THICKNESS The Rulison Field study area borders the Grand Hogback, a steeply dipping outcrop of rocks which forms the eastern structural and geographic boundary of the Piceance Basin. The tilted rocks of the hogback are a result of Laramide orogenic events occuring near the end of Mesaverde deposition in the basin. Paralleling the strike of the Grand Hogback in the southeast basin area are several major anticlines which influence the subsurface structure of the Mesaverde Group sediments. Most notably, these are the Divide Creek Anticline, Baldy Creek Anticline and Wolf Creek Anticline. The subsurface structure on the top of the Mesaverde Group in the Rulison Field study area is illustrated in Figure 3. The structure of the eastern one third of the mapped area is dipping approximately 3 (.052 rad) to the northwest. The subsurface structure here is possibly a continuation of the northwesterly plunging Divide Creek Anticline directly to the southeast of the plunging Divide Creek Anticline directly to the southeast of the mapped area. P. 47
- Geology > Structural Geology > Tectonics > Compressional Tectonics > Fold and Thrust Belt (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- North America > United States > Utah > Uintah Basin > Wasatch Formation (0.99)
- North America > United States > Colorado > Piceance Basin > Williams Fork Formation (0.99)
- North America > United States > Colorado > Piceance Basin > Rulison Field > Mesaverde Formation (0.99)
- (4 more...)
Abstract The Multi-Well Experiment (MWX) is a research-oriented field laboratory whose objective is to develop the understanding and technology to allow economic production of the several years supply of natural gas estimated to be within the low permeability, lenticular gas sands of the Western permeability, lenticular gas sands of the Western United States. Features of MWX include:three closely-spaced wells (115โ215 ft, 35โ66 m) for reservoir characterization, interference testing, well-to-well geophysical profiling, and placement of diagnostic instrumentation adjacent to the fracture treatment; complete core taken through the formations of interest; a comprehensive core analysis program; an extensive logging program with conventional and experimental logs; determination of in situ stresses in sands and bounding shales; use of various seismic surveys and sedimentological analyses to determine lens morphology and extent; use of seismic, electrical potential, and tilt diagnostic techniques for hydraulic fracture characterization; and a series of stimulation experiments to address key questions. This paper presents the current MWX accomplishments resulting from the 1983 field season which featured the drilling of a third well and the first stimulation experiment. Introduction and Background For a number of years the United States government has engaged in research to enhance gas recovery from unconventional reservoirs, such as organically-rich fractured shale and discontinuous, lenticular, tight sandstones. Large quantities of natural gas are trapped in these formations, whose permeabilities are too low to permit economic permeabilities are too low to permit economic recovery by conventional technology. In the western United States, the Greater Green River, Piceance, Wind River, and Uinta basins have been identified as containing significant amounts of gas in thick sections of lenticular sands. The National Petroleum Council has appraised' these four basins Petroleum Council has appraised' these four basins to hold 136 TCF (4 TM3) of maximum recoverable gas in lenticular reservoirs. This sizeable resource is now being investigated by the U.S. Department of Energy (DOE) in the Piceance basin of western Colorado, where a field laboratory containing three closely spaced wells penetrating the lenticular Mesaverde formation has been constructed. This facility, near the town of Rifle, is the site of the DOE Multi-Well Experiment (MWX), which has been developed to determine the viability of the lenticular tight sands as a gas resource. Massive hydraulic fracturing has demonstrably increased gas production from tight reservoirs, but currently its performance in lenticular formations is unpredictable. This results from poor definition of reservoir properties, inadequate understanding of the physics controlling fracture propagation and proppant transport, limited ability to measure, proppant transport, limited ability to measure, describe, or evaluate the created fracture, and uncertainty as to the relationship of stimulation design variables (fluids, proppants, pumping rates) to the resulting fracture. These difficulties are compounded in the lenticular formations by the uncertainty whether multiple lenses, some remote from the wellbore, can be stimulated by a common treatment. Improved understanding, evaluation, prediction, and possible control of stimulation prediction, and possible control of stimulation technology are needed for effective development of tight lenticular reservoirs. The ultimate aim of the MWX is to determine the optimum stimulation technology for increasing the gas recovery from tight gas sand formations, specifically the tight lenticular formations of the basins of the western United States. Further discussion of the rationale, plans, objectives and activities can be found in References 2โ5. Experiments are now being conducted at the MWX site to 1) provide improved definition of the reservoirs through extensive core and log analyses, well and stress testing, and geologic and geophysical studies, and to 2) investigate the effectiveness of stimulation technology with diagnostic instrumentation and production performance testing. performance testing. P. 351
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.45)
- Geophysics > Seismic Surveying (1.00)
- Geophysics > Borehole Geophysics (1.00)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Colorado > Piceance Basin > Williams Fork Formation (0.99)
- North America > United States > Colorado > Piceance Basin > Mesaverde Formation > Williams Fork Formation (0.99)
- North America > United States > Wyoming > Wind River Basin (0.94)
- (6 more...)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- (4 more...)
The paper was presented at the SPE/DOE Unconventional Gas Recovery Symposium of the Society of Petroleum Engineers held in Pittsburgh, PA. May 16โ18, 1982. The material is subject to correction PA. May 16โ18, 1982. The material is subject to correction by the author. Permission to copy is restricted to an abstract of not more than 300 words Write: 6200 N. Central Expwy., Dallas, TX 75206. Abstract Two research wells were drilled and completed in a known, yet heretofore unproductive tight sand gas reservoir in the Green River Basin. Although previous wells were drilled in the area and previous wells were drilled in the area and hydraulically fractured, there has been no commercial production. The consideration of advanced methods production. The consideration of advanced methods of stimulation design aid changing gas prices caused recent renewed interest. A systematic approach led to successful fractures of one zone in each of the two wells. Initial production rose from 107 to 4150 MCFD in one well and from 35 to 1450 MCFD in the second well after stimulation treatments. Introduction The Pinedale gas field is a large tight sand reservoir located in Sublette County, Wyoming (see Figure 1). The magnitude of this resource is indicated by a National Gas Survey Advisory Committee report of 1977 which lists in-place gas reserves of 37 trillion cubic feet. Eleven wells were drilled into the Fort Union formation of this field between 1939 and 1963. Six wells were subjected to conventional hydraulic fracturing. Three of these six wells later underwent massive hydraulic fracturing treatments during the period 1974 to 1976; however, these treatments failed to significantly increase the long-term production potential and there has never been commercial production from this field. Based on advances in the technology of tight sand production, Mountain Fuel Supply Company, with the production, Mountain Fuel Supply Company, with the technical assistance of Terra Tek Incorporated, initiated an extensive research and development program in the area. The program involved a critical review of all prior data, drilling of two 12,000-foot wells, flow testing of existing wells, extensive logging of the new wells, theoretical fracture design studies, and prestimulation and poststimulation flow testing of the new wells. The fracture design work included a critical investigation of in-situ stress and fracture orientation and propagation. The laboratory work included special core testing with candidate fracturing fluids and proppants. This paper presents details of the study and the associated laboratory and field results. Funding assistance was provided by the United States Department of Energy and the Gas Research Institute. Background The Pinedale gas reservoir is located on the west of an anticline with a northwest-southeast trend. It is 30 to 40 miles long and approximately 5 miles wide, with approximately 2,000 feet of vertical relief from the lowest to the highest structural elevation. The anticline was formed by compressional stresses resulting from the Wind River Uplift on the east and the Wyoming Overthrust on the west during the Laramide Orogeny (appx. 100 million years B.C.). Gas-bearing sandstone units are encountered at approximately 8,000 feet in depth and continue, interbedded with shale, downward to an undefined depth, but at least as deep as the total depth (19,300 feet) of the El Paso Natural Gas Company's Wagon Wheel well. Evaluation of the data obtained from that well indicates, however, that a significant portion of the presently known gas in the field is contained in the formation interval from 9,000 to 11,700 feet. The individual sandstone units range in thickness from a fraction of an inch to several tens of feet. Log information from other Pinedale wells and outcrop studies in the Green River Basin indicates that the Fort Union sands are lenticular with the total gross sand thickness from 500 to 700 feet. Core data measured from wells indicate porosities of 8 to 10 percent with 50 to 59 percent water saturation. El Paso Natural Gas Company investigations of the Pinedale reservoir characteristics, for samples with 8.8 percent porosity and 50.6 percent water saturation, showed permeability to gas of less than 0.001 millidarcy. P. 313
- North America > United States > Wyoming > Sublette County (0.69)
- North America > United States > Texas > Dallas County > Dallas (0.24)
- North America > United States > Pennsylvania > Allegheny County > Pittsburgh (0.24)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Mineral (1.00)
- Geology > Structural Geology > Tectonics > Compressional Tectonics > Fold and Thrust Belt (0.74)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Wyoming > Green River Basin > Pinedale Field (0.99)
- North America > United States > Utah > Green River Basin (0.99)
- North America > United States > Gulf of Mexico > Western GOM > West Gulf Coast Tertiary Basin > Keathley Canyon > Well No. 1 (0.98)
- North America > Canada > Alberta > Pinedale Field > Baysel Pinedale 6-7-54-16 Well (0.98)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (0.95)
The paper was presented at the SPE/DOE Unconventional Gas Recovery Symposium of the Society of Petroleum Engineers held in Pittsburgh, PA, May 16โ18, 1982. The material is subject to correction PA, May 16โ18, 1982. The material is subject to correction by the author. Permission to copy is restricted to an abstract of not more than 300 words. Write: 6200 N. Central Expwy., Dallas, TX 75206. Introduction Reliable evaluation of hydrocarbon resources encountered in shaly clastic reservoirs of low porosity and low permeability is an important although difficult task. Log-derived estimates of the volume, type and distribution modes of various clay minerals, determination of cation exchange capacity (CEC) and Qv (CEC per unit of total pore volume), and properly selected water saturation calculation models assist formation evaluation. Since shaly clastic reservoir rocks require extensive core sampling for CEC and Qv analysis, which is tedious, time consuming, and expensive, attempts have been made to correlate such CEC and Qv data with one specific or a combination of several well logging measurements. The latter include the spontaneous potential, gamma ray, natural gamma ray spectral data, dielectric constant and acoustic-, density- and/or neutron-derived porosity, etc. Constraints associated with these concepts will be reviewed. Discussed in this paper, is an innovative digital shaly sand evaluation approach (CLASS), which provides information on total and effective reservoir porosity, total and effective fluid distribution based on the Waxman-Smits equation, reservoir productivity, silt volume, and volumes, types and distribution modes of clay minerals present in subsurface formations. Both basic concepts and field case examples will illustrate this method. CLAY MINERALS Clay minerals, used as a rock and particle term, describe an earthy, fine-grained, natural material which develops plasticity when mixed with a small amount of water. Such clay minerals significantly affect important reservoir properties such as porosity, water saturation, and permeability. Clay minerals are composed of small crystalline particles which are classified according to their crystal particles which are classified according to their crystal structure. Important ones of interest to the petroleum engineer and geologist are kaolinite, montmorillonite, illite, chlorite, and mixed-layer minerals. They are essentially layered hydrous aluminum silicates which may contain small amounts of alkalies and alkaline earths and have some substitution of aluminum by other cations, such as magnesium, iron, etc. The most common clay minerals, their composition, matrix density, hydrogen index, CEC, and distribution of potassium, thorium, and uranium based on natural gamma ray spectral information are listed in Table 1.Numerous experimental data show that the CEC value of clays is directly related to their capacity to absorb and hold water. Clays of the montmorillonite (smectite) group have the greatest capacity to absorb water and also the highest CEC values. Kaolinite and chlorite have very low CEC, and their capacity to hold water is also low. Shales can be defined as an earthy, fine-grained, sedimentary rock with a specific laminated character. Based on the analyses of 10,000 shales Yaalon describes the mineral composition of the average shale as follows: clay minerals (predominantly illite), 59%; quartz and chert, 20%; feldspar, 81%; carbonates, 71%; iron oxides, 30%; organic materials, 1%; others, 2%. Generally speaking, illite appears to be the dominant clay mineral in most of the shales investigated. Chlorite mica is frequently present, smectite is a common component in Mesozoic and younger shales, and kaolinite usually occurs in small amounts only. Therefore, a typical shaly clastic reservoir rock and/or a typical shale formation may consist of several components. Hence, no universal shale parameter can be used to characterize a specific type of argillaceous sediment or rock. P. 67
- North America > United States > Texas > Dallas County > Dallas (0.24)
- North America > United States > Pennsylvania > Allegheny County > Pittsburgh (0.24)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Mineral > Silicate > Phyllosilicate (1.00)
- South America > Venezuela (0.99)
- North America > United States > Texas > East Gulf Coast Tertiary Basin > Wilcox Formation (0.99)
- North America > United States > Oklahoma > Anadarko Basin > L Formation (0.99)
- (4 more...)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
The paper was presented at the SPE/DOE Unconventional Gas Recovery Symposium of the Society of Petroleum Engineers held in Pittsburgh, PA, May 16-18, 1982. The material is subject to correction by the author. Permission to copy is restricted to an abstract of not more than 300 words. Write: 6200 N. Central Expwy., Dallas, TX 75206. Abstract Current estimates of gas in place in the Devonian Shales of the Appalachian Basin range up to 2,500 TCF. For the most part, the majority of this resource is tied up in the shale matrix and the source and reservoir of this gas is the same as the low permeability and porosity of the shale prevents migration of the gas to a more classical reservoir rock. Where there is fracturing of the shales, the fracture network serves as a reservoir and wells drilled in the area of fracturing tend to be good producers. producers. For exploration purposes, the most probable areas for drilling of the shales are those that have a high density of natural fracturing. Aerial photography has been used to locate potential drilling sites in the Basin. photography has been used to locate potential drilling sites in the Basin. The use of this technique is based upon the premise that fractures evident in surface sediments are often useful indicators of subsurface fracturing favorable for the accumulation of hydrocarbons. Buried fault traps, anticlines, and salt domes are frequently revealed by surface fault configurations or locally anomalous joint orientations. Moreover, since fractures are frequently conduits and collection sites for hydrocarbons, a concentration of surface fractures may indicate a potential productive reservoir at depth. productive reservoir at depth. Aerial photography allows fractures to be recognized and mapped in almost every type of terrain and soil cover. A photogeological study designed to aid in the location of specific prospects typically begins with a study of LANDSAT photos to spot large scale features. This is followed by a study of stereoscopic photo pairs and photomosaics of larger scale. For pinpointing drilling sites in such cases, the greatest weight is placed on the interpretations from stereoscopic photo pairs. geology, the techniques used in applying aerial photography as an exploration tool and finally the application of photogeology in identifying specific well sites in the Devonian Shales of the Appalachian Basin. Introduction Structures responsible for conventional hydrocarbon traps such as anticlines, fault closures, and salt domes are frequently indicated by surface fault configurations or locally anomalous joint orientations. Joint patterns are sometimes also useful in the diagnosis of stress forces that produce folds, wrench faults, etc. Furthermore, since fractures are frequently conduits for both hydrocarbons and metallic minerals, a concentration of surface fractures may sometimes indicate fracture networks that serve as the reservoirs for hydrocarbons at depth, or vein-type mineral lodes. This paper describes the use of aerial photographs to locate fractures, and subsequently to locate drilling sites in Erie County, Pennsylvania, where the traps in the Devonian shale and the underlying Pennsylvania, where the traps in the Devonian shale and the underlying sands are stratigraphic. In the shales, porosity for gas is provided mainly by intersecting networks of natural fractures into which gases migrate from the very impermeable shales. In a study such as this, it is important for the geologist to identify and map surface traces of fractures as accurately as possible because such fractures are remarkably ubiquitous. However, in some areas man-made artifacts, that are easily confused with fracture traces, are almost as ubiquitous as well. Careful analysis backed by field experience is essential to discriminate between the two; and field verification is recommended in the most detailed work. p. 51
- North America > United States > Texas > Dallas County > Dallas (0.24)
- North America > United States > Pennsylvania > Erie County (0.24)
- North America > United States > Pennsylvania > Allegheny County > Pittsburgh (0.24)
- Geology > Structural Geology (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.30)
- North America > United States > West Virginia > Appalachian Basin (0.99)
- North America > United States > Virginia > Appalachian Basin (0.99)
- North America > United States > Tennessee > Appalachian Basin (0.99)
- (8 more...)
The paper was presented at the SPE/DOE Unconventional Gas Recovery Symposium of the Society of Petroleum Engineers held in Pittsburgh, PA. May 16โ18, 1982. The material is subject to correction PA. May 16โ18, 1982. The material is subject to correction by the author. Permission to copy is restricted to an abstract of not more than 300 words Write: 6200 N. Central Expwy., Dallas, TX 75206. Abstract The San Juan Mountain igneous extrusive complex in southwestern Colorado is approximately equidistant from the southeastern Piceance, northern San Juan, and western Raton Basins. These areas are known to contain high-rank coals and to have high methane contents in those coals. Recent studies have shown that this area is the center of an anomalously high geothermal gradient, which may strongly influence the increased coal rank and therefore the gas content in those areas. Other, less extensive Tertiary igneous events locally influencing coal rank and methane content include the intrusives along the margin of southeastern Piceance Basin, northeastern San Juan Basin, and Piceance Basin, northeastern San Juan Basin, and the volcanic extrusives associated with the Spanish Peaks of the Raton Mesa. Peaks of the Raton Mesa. Coal samples collected in the Piceance Basin increase in gas content from west to east from approximately 200 cubic feet per ton (cf/t) (6.3 cubic centimeters per gramโcc/g) along the Colorado River in the vicinity of Cameo to greater than 1,000 cf/t (31.3 cc/g) in the vicinity of Coal Basin in the southeastern part of the basin near the Elk Mountain intrusives. Coal samples from the Fruitland Coal in northern New Mexico and southern Colorado in the San Juan Basin have been shown to contain in excess of 500 cf/t (15.6 cc/g). Samples collected by the USGS in the Raton Basin from the Vermejo Formation contain in excess of 500 cf/t (15.6 cc/g). It is suggested here that the anomalously high geothermal gradients induced by the intrusion of the San Juan Mountain complex and aided locally by other Tertiary events is substantially responsible for the high-rank coals observed in these areas, and therefore is principally responsible for the anomalously high methane content and the high potential for coalbed methane production from these potential for coalbed methane production from these areas. Introduction For the last four years, studies have been made on the potential for production of methane from coalbeds in numerous areas of the United States. Principal among those areas were the Piceance, San Juan, and Raton Basins of the Rocky Piceance, San Juan, and Raton Basins of the Rocky Mountain West. Two of these areas, the Piceance and San Juan Basins, have been identified as major dry gas-producing regions in the United States. While the San Juan Basin has been recognized as a major gas producer for a number of years, the Piceance Basin has only recently been identified as Piceance Basin has only recently been identified as a major gas province. Close examination of these individual basins indicates that the southeastern Piceance and the northern San Juan are Piceance and the northern San Juan are predominantly gas-rich. These two areas, along with the predominantly gas-rich. These two areas, along with the western part of the Raton Basin, have been identified as having characteristics suggestive of coalbed source for much of the dry gas. This paper will present a discussion of the development of gas resource in the subject basins and why the particular portions of those basins are gas-rich. particular portions of those basins are gas-rich. THEME: DIFFERENTIAL HEATING OF BASIN COALBEDS CREATES METHANE EXPLORATION TARGETS High-rank coals and their attendant high gas contents have been observed during testing of coalbeds in parts of the southeastern Piceance and northern San Juan Basins in Colorado and New Mexico. Generally, areas of high coalbed methane potential can be identified on the basis of: potential can be identified on the basis of:Depth of burial Thickness of coal Rank of coal In the particular areas of interest, all of the requisite characteristics were observed except depth of burial. In both the Piceance and the San Juan, coal rank and observed gas content tend to increase in the shallower coals located in the southeastern and northern portions of the respective basinsโโtoward the same center. P. 151
- North America > United States > New Mexico > Colfax County (1.00)
- North America > United States > Colorado (1.00)
- North America > United States > Texas > Dallas County > Dallas (0.24)
- North America > United States > Pennsylvania > Allegheny County > Pittsburgh (0.24)
- Geology > Rock Type > Sedimentary Rock > Organic-Rich Rock > Coal (1.00)
- Geology > Rock Type > Igneous Rock (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.97)
- Energy > Renewable > Geothermal (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.49)
- North America > United States > Texas > Maverick Basin > Somerset Field (0.99)
- North America > United States > Texas > Fort Worth Basin > Denver Field (0.99)
- North America > United States > New Mexico > San Juan Basin > Mesa Field (0.99)
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- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Coal seam gas (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Non-Traditional Resources > Geothermal resources (1.00)
The paper was presented at the SPE/DOE Unconventional Gas Recovery Symposium of the Society of Petroleum Engineers held in Pittsburgh, PA, May 16-18, 1982. The material is subject to correction by the author. Permission to copy is restricted to an abstract of not more than 300 words. Write: 6200 N. Central Expwy., Dallas, TX 75206. Abstract In mid-1981, the Gas Research Institute (GRI) drafted comprehensive programs for research directed toward increasing the national supply of programs for research directed toward increasing the national supply of natural gas from unconventional sources. Low-permeability (tight) gas sands are one of these sources. GRI's predraft planning for the tight gas sands program was for a duration of about one year and included workshops with advisors from the natural gas industry. The resulting program plan for tight gas sands research is oriented to industry participation and field testing. Research results are freely distributed to a wide variety of users. The tight gas sands program is initiating in 1982 planning updates by GRI are on an annual cycle. GRI is proceeding with six projects for tight gas sands research, involving analyses for producing natural gas from tight blanket sands that are presently considered as non-commercial. The program plan is comprised of a sequence of projects relating to resource plan is comprised of a sequence of projects relating to resource identification, formation evaluation, fluids and proppants investigations, fracture design, reservoir modeling, and staged field tests with technology transfer. Accelerated research work is scheduled for 1983, with emphasis on field evaluations beginning in 1984. This paper describes the philosophy, objective, and content of the GRI program plan, which is currently scheduled through 1988. Accomplishment of program plan, which is currently scheduled through 1988. Accomplishment of the program is expected to provide for significant advances in tight gas sands research. GRI is a non-profit scientific organization which contracts applicable research work to others for benefit to the natural gas industry and to natural gas consumers. Introduction Significant quantities of natural gas exist in low-permeability (tight) sands across the United States. The recoverable gas potential of these tight sands is very large; a current estimate places recoverable reserves as high as 574 trillion cubic feet (Tcf.). However, a combination of economic uncertainties and technical limitations has prevented widespread commercial exploitation of this resource. The Federal Energy Regulatory Commission has issued a special incentive pricing mechanism for tight gas reservoirs, and has designated numerous formations as eligible for incentive pricing. However, this action has not encouraged uniform development and production of gas from tight sand formations. To date, resource development has occurred primarily in limited areas. In these areas, state-of-the-art technologies primarily in limited areas. In these areas, state-of-the-art technologies can be used in conjunction with a limited knowledge of the formation characteristics to stimulate economic production rates. Successful research and development in exploitation technology is necessary if the full potential of tight gas sands is to be realized. In recent years, the strategy of the Gas Research Institute (GRI) has been to perform research and development (R and D) in support of ongoing industry and government programs, and to take advantage of important opportunities not budgeted in R and D programs of others. With the advent of budget cuts in the U.S. Department of Energy, and the concurrent realignment of government priorities and objectives toward more long-term, high-risk research, GRI is shifting its strategy, and is taking a lead role in implementing a comprehensive program to develop the technology necessary for gas extraction from tight sand formations. RESEARCH OBJECTIVE The objective of this GRI program is to develop the technology necessary to achieve gas recovery from blanket tight gas sands that are not exploitable using current gas recovery methods and to maximize the potential through industrial cofunding and participation. potential through industrial cofunding and participation. THE GRI TIGHT GAS SAND PROGRAM The necessary R and D in tight gas sands present complex problems. The resource is dispersed over a large geographic area and occurs in a wide variety of geologic environments as indicated in Figure 1. p. 177
- North America > United States > Wyoming (0.69)
- North America > United States > Colorado (0.69)
- North America > United States > Texas > Dallas County > Dallas (0.24)
- North America > United States > Pennsylvania > Allegheny County > Pittsburgh (0.24)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Wyoming > Wind River Basin (0.99)
- North America > United States > Wyoming > Uinta Basin (0.99)
- North America > United States > Wyoming > Sand Wash Basin (0.99)
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- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Tight gas (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
Abstract Potentially recoverable quantities of methane from unconventional sources such as coalbeds have been largely excluded from potential gas supply surveys. This is attributable to the lack of data about the resource, technology and economics of its recovery. In order to provide answers, DOE initiated the Methane Recovery from Coalbeds Project (MRCP) to characterize the gas-in-place for various coalbeds and associated sediments. After the 1977 initiation of the MRCP, several other interested groups have supported various aspects of the project. Results are presented from the first phase of a joint effort between DOE (METC), TRW, GRI, and Industry to investigate the coalbed methane resource in the Arkoma basin. This elongated narrow eastwest sedimentary basin is located in east-central Oklahoma and in west-central Arkansas and contains extensive gaseous bituminous coal reserves of Pennsylvanian age. Preliminary gas-in-place Pennsylvanian age. Preliminary gas-in-place resource estimates were made based on the volume of coal in-place and on direct methane desorption data. It has been conservatively estimated that the total coal resource of the basin is about 7.9 billion tons. Seven individual coal seams have been identified as being the most likely candidates to contain potential coalbed gas reservoirs. The majority of these coalbeds are continuous, but these beds do not maintain a constant thickness throughout the basin. Total gas contents, as determined by desorption tests on coal cores, range from 73 cubic feet per ton to 576 cubic feet per ton. The estimated unscaled in-place methane resource is 1.6 Tcf and is considered a low volumetric assessment for the basin. The estimated depth scaled in-place methane resource is 2.7 Tcf, 82 percent of which is contained in the Hartshorne percent of which is contained in the Hartshorne coalbeds. Analyses of gas produced from the Hartshorne coals/Hartshorne Formation show a range of Btu values from 993 to 1118 in the western part of the basin. A viable exploration rationale has been established for the Arkoma basin, based on various geological aspects, such as stratigraphy and structure, the depth of the coalbeds and the recent MRCP well tests. The described methodology of methane exploration is present along with the results. Redefined target-test areas in the basin have been delineated and are discussed. Introduction This study is a result of a cooperative effort between DOE (METC), TRW, GRI and the Natural Gas Industry to characterize and establish the methane resource associated with coalbeds in the Arkoma basin. These activities were initiated in 1979 as part of the Methane Recovery from Coalbeds Project part of the Methane Recovery from Coalbeds Project (MRCP). Also, the USBM is doing a study in the Arkoma basin which will determine the effect of geology and occurrence of the emission of methane during mining operations (Iannacchione and Puglio, 1979). The Arkoma basin encompases an area of approximately 13,488 square miles in the southcentral United States, approximately 41% of which is in the State of Oklahoma (Fig. 1). The basin is an east-west trending depression 250 miles long, 25 to 50 miles wide, and contains Pennsylvanian age and older sedimentary rocks. Except for largescale faulting and folding in the trough portion of the basin, the shelf and sub-shelf are reasonably uncomplicated structurally. The shelf has been least disturbed by the Ouachita influence. Extensive Pennsylvanian age bituminous coal reserves and some semi-anthracite reserves are contained in the basin. Deepest coal bearing portions of the basin occur in a broad area centered around southern Pittsburg, central Latimer, southern Haskell, central Le Flore counties, Oklahoma and west-central Sebastian County, Arkansas. Because of the basin's central location and proximity to interstate pipelines, the Arkoma basin is an attractive potential gas resource area. P. 29
- North America > United States > Arkansas (1.00)
- North America > United States > Oklahoma > Oklahoma County (0.50)
- North America > United States > Oklahoma > Le Flore County (0.35)
- North America > United States > Oklahoma > Mcalester Basin (0.99)
- North America > United States > Oklahoma > Arkoma Basin > Cana Woodford Shale Formation (0.99)
- North America > United States > Arkansas > Arkoma Basin > Cana Woodford Shale Formation (0.99)
- Africa > Middle East > Libya > Murzuq District > Murzuq Basin > Block NC 115 > Field A Field > Silurian Tanezzuft Formation > A17 Well (0.99)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Coal seam gas (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 > Formation Evaluation & Management (1.00)