|Theme||Visible||Selectable||Appearance||Zoom Range (now: 0)|
Producers currently develop Devonian shale gas fields by drilling wells which offset a high productivity well. Remote sensing as well as productivity well. Remote sensing as well as various geophysical and geochemical techniques are sometimes used to site wells. Yet, productivity of the development wells can be highly variable. In an attempt to improve the production potential of these wells, the Gas Research Institute has undertaken a research program aimed at developing a better understanding of the geological features which control production in the shale, and which a wellbore must intersect or communicate with in order to result in higher productivity. A better understanding of these geological production controls is necessary to develop an exploration or stimulation methodology which will enable the producer to better locate and stimulate wells, and producer to better locate and stimulate wells, and thus improve overall productivity of the field.
An analysis of production figures from the Devonian Shale suggests that there is a need to concentrate on how to find the most productive areas in a given field, and to develop better stimulation design criteria to enhance productivity. It is not unusual for a small number of productivity. It is not unusual for a small number of wells, say 15%, to be responsible for nearly half of the total production in a field. The best producers in a field rarely require stimulation producers in a field rarely require stimulation while marginal and submarginal wells must be stimulated to achieve economic production. A variety of stimulation techniques are typically used ranging from shooting to hydraulic fracturing. However, the best strategy for choosing a particular stimulation technique in a particular particular stimulation technique in a particular set of conditions is not fully understood.
Studies under the Eastern Gas Shales Program (EGSP) of the Department of Energy have shown that gas is contained in the rock matrix throughout the Appalachian basin. However, economic production of this gas requires the development of permeable pathways, and the ability to intersect these pathways, and the ability to intersect these pathways from a wellbore. It is most likely t pathways from a wellbore. It is most likely t the variations in production which are observed many shale fields are the result of the interrelationships of the specific permeable pathways which are intersected by the wellbore. However, other factors could contribute to the observed variability in production including pressure depletion of the reservoir, and drilling and completion practices. These factors must be taken into account practices. These factors must be taken into account in any analysis.
In order to improve existing exploration and production strategies it is therefore necessary to production strategies it is therefore necessary to establish a better understanding of the permeable pathways which allow gas to migrate from the pathways which allow gas to migrate from the matrix to the wellbore. These permeable pathways could include such geological features as fractures, silts and interbedded laminae and bedding planes. In addition gas diffusion from the matrix planes. In addition gas diffusion from the matrix will contribute to the production characteristics of a shale wells.
Considerable work has already been carried out in this area, in particular in the development of dual porosity models which include the effects of a fracture dominated permeability and a matrix porosity. However, a better understanding of the porosity. However, a better understanding of the relationships of the various storage and permeability elements of a shale reservoir is still permeability elements of a shale reservoir is still needed for a number of reasons. Thus:
Existing fracture porosity shale gas models can require a fracture area greater than 109 sq ft/sqmi to account for observed productivity. This fracture area may be greater than has been observed in nature.
Planes of enhanced permeability, such as bedding planes and silt laminae, are frequently observed. The existence of these planes can greatly reduce the fracture area required to account for observed production from a fractured reservoir.
Multizone completion opportunities in the Appalachian basin are being investigated by Columbia Gas under contract to DOE to encourage exploitation of Devonian shale gas reserves into regions extending beyond the borders of historic shale production. Data presented within this paper show that Devonian presented within this paper show that Devonian shale gas potential can be economically exploited in areas removed from historic shale production through: (1) dual or multiple completion of wells targeting nonshale formations, and (2) recompletion of existing nonshale producing wells to the Devonian shale.
Research sponsored through USDOE's Eastern Gas Shale Program and GRI's Devonian Shale Exploration and Production Studies has resulted in significant contributions towards understanding the Devonian shale. Geological, reservoir, and producing characterization have occurred as a result of developments in coring, geophysical well log interpretation, well test analysis, hydraulic fracturing stimulation, and mathematical modeling. Research efforts sponsored by USDOE and GRI have expanded and continue to expand our knowledge of mechanisms controlling production and recovery efficiency. Unfortunately, these efforts have provided little in the way of industry development of new Devonian shale gas reserves beyond historically productive regions. The economic climate in recent history has contributed little to encourage Devonian shale gas exploitation: development remains at a minimum in most historical areas and is virtually nonexistent elsewhere in the basin. Outside historical shale areas, economics are typically marginal or worse for wells specifically targeting the Devonian shale.
Outside historic regions, targeting a new well specifically for Devonian shale gas carries high risk, especially in terms of economic viability. While it is highly probable that Devonian shale gas would be encountered, marginal or submarginal profitability is likely and would do little to promote further development outside areas of historic production. Also given the current economic production. Also given the current economic climate and state of extraction technology as applied to the Devonian shale, it is unlikely that near future development of shale gas will expand much beyond the current confines of historic production.
In many parts of the basin potentially Productive formations coexist, some of which Productive formations coexist, some of which produce gas concurrently. Many horizons produce gas concurrently. Many horizons produce in geographical localities outside produce in geographical localities outside historical Devonian shale production but in areas which demonstrate Devonian shale gas potential. potential. One way to minimize risk and develop new Devonian shale gas is through multiple completions. This practice, which occurs in many historic shale producing areas, has potential to dramatically improve well economics. potential to dramatically improve well economics. This approach is particularly attractive as a means of developing areas of nonhistoric Devonian shale production where operators are presently targeting other formations for presently targeting other formations for completion.
For a minimal incremental cost (compared to that of a well specifically targeted to the Devonian shale), Devonian shale production potential could be established beyond its potential could be established beyond its current geographic confines.
Evaluation of production data in Southwestern West Virginia had identified five Devonian shale well type categories and average reservoir properties associated with each category. Permeability-thickness product can be uniquely identified from history matching product can be uniquely identified from history matching regardless of the variability of other match parameters. Pressure buildup analyses conducted on three wells Pressure buildup analyses conducted on three wells confirms this. A simple relationship exists between the permeability-thickness product and ten-year cumulative production. History match data suggest that natural fracture property variations result in well quality variations.
Columbia Gas is conducting a study to determine production controls presently active in a production controls presently active in a Southwestern West Virginia study area (Figure 1). This will be accomplished by determining the stratigraphic location and rate of existing gas flows and relating this information to the geological characteristics of each flow zone.
Attempts will then be made to establish a correlation between the production control features identified and actual production performance. Eight unstimulated shale wells completed open-hole provide the basis for this characterization. Analyses include that of: pre- and post-cleanout well tests; open-hole logs; flow data; and sidewall cores. The results of the characterization work then may be extended to a larger geographical area on the basis of relationships established from production data analysis.
The purpose of the production data analysis work is to describe be gas flow from Devonian shale wells. The practical outcome of this analysis is the identification of general producing categories and determination of reservoir properties unique to a given group of wells. Since production is usually the only abundant source of information available for evaluating the Devonian shale, reservoir simulators are relied upon to a great extent. This endeavor utilizes the two mathematical models, SUGAR-MD and an analytical model developed by S. A. Holditch and Associates, Inc.
This paper presents information regarding: (1) decline curve typing using decline curve profiles and normalized matrix production data; (2) history matching using two different mathematical models; and (3) pressure buildup results from three shale wells.
The relationships developed here indicate that well quality and future productivity can be identified early in the life of a well. This has important implications in developing an exploration/exploitation plan targeting potential high quality shale well plan targeting potential high quality shale well drilling sites.
WELL TYPE CLASSIFICATION
Devonian shale production performance strongly suggests the presence of a dual porosity reservoir. Production decline curves usually consist of two Production decline curves usually consist of two distinct segments. Figure 2 demonstrates this behavior. The early part of the curve demonstrates relatively high initial flow rates which rapidly decline; this is characteristic of natural fracture depletion. The latter section of the curve shows a long period of low flow rate with very little decline; this indicates a matrix of very low permeability. The matrix acts as the primary source permeability. The matrix acts as the primary source of gas, whereas the natural fractures provide the means for gas to get to the wellbore.
Ninety-four individually metered gas wells were used to establish the four major and one transitional decline curve classifications in our study area. Two techniques were used in identifying (and in cross-checking) decline categories, namely, matrix gas normalization and production decline profiles.
The evaluation of reservoirs which are predominantly shale presents a problem for engineers predominantly shale presents a problem for engineers who have been traditionally educated to either correct for or ignore such lithologic zones. Currently accepted evaluation techniques and their applicability are discussed to determine how best to forecast remaining recoverable gas reserves from the Devonian Shales of the Appalachian Basin. This study finds that rate-time decline curve analysis is the most reliable technique, conditionally, and presents typical decline curves for a three-state presents typical decline curves for a three-state area, three completion conditions, and the individual states based on production data gathered from 508 shale wells. The resultant type curves illustrate a dual (or multiple) porosity mechanism which violates standard decline curve analysis guidelines. The results, however, are typical not only for the Devonian Shales but all naturally fractured, multi-layered, or predominantly shale reservoirs.
An evaluation rationale for the Devonian Shales has long eluded petroleum engineers. Since the first shale gas well was completed in 1821 through the shale promoter's heyday in the late 1970's and early 1980's, only the surface has been scratched regarding any predictive algorithms. Despite the extensive studies undertaken by and for the Department of Energy many operators still use 19th century exploration and development techniques and, if their efforts are successful, complete a gas well whose reserve estimates may be largely unsubstantiated. Usually their efforts are successful; the success ratio for Devonian Shale wells is in excess of 90 percent.
A review of the accepted engineering practice evaluation methods must be critically analyzed to see which, if any, can be used in a naturally fractured shale reservoir.
Gas bearing Devonian Shales cover an approximate 275,000 square mile area within the Appalachian, Michigan, and Illinois Basins. This paper addresses the Appalachian Basin, where in paper addresses the Appalachian Basin, where in excess of 9,600 wells produce from the shales, and in particular the study area outlined on Figure 1. This study area also represents a region of similar geologic, geochemical, and reservoir engineering character compared to the west-to-east or north-to-south trends of the much larger Appalachian Basin.
The first thing an engineer must realize is that there is no one horizon known as "the Devonian Shale", but rather a series of strata above the Onondaga limestone (Big Lime) and below the Berea sandstone of Lower Mississippian age, as shown on Figure 2 (8). These strata are almost pure shale in western Ohio, but grade or diverge into siltstones in central and southeastern West Virginia (where they become the Devonian Sands). Depth of deposition varies considerably, from only a few hundred feet in western Ohio (outcropping) to more than 11,000 feet in eastern Pennsylvania. The thickness increases proportionately also.
Gas is produced from the reservoir by a natural fracture system, believed to be associated with a geological structure known as the Rome Trough. Gas release is accomplished in a step-wise fashion, first as free gas in the fractures, then as adsorbed gas stripped from its adhesion to fracture surfaces, and finally as absorbed gas bleeding out of the shale matrix. The free gas flushes quickly at a high rate, but adsorbed gas is produced slowly in low volumes. produced slowly in low volumes.
A variety of completion and stimulation practices have been used in Eastern Devonian Shale practices have been used in Eastern Devonian Shale wells during the more than 60 years since its initial development. Over 1000 wells in thirty-four counties located in the west central part of the Appalachian basin, were analyzed to investigate the effects of these practices on well productivity. This study represents the largest productivity. This study represents the largest investigation to date of post-treatment response using a reliable indicator of the well's long-term deliverability for comparing both explosive and hydraulic fracturing methods.
The traditional measure of well productivity, initial open flow, gives a poor indication of the well's long-term potential. The cause of this poor relationship can be partially attributed to the insufficient test times run during open flow measurements. A more representative indicator of long-term potential, available early in the well's life, has been identified.
Based on location data from wells in the study area, field development of the Devonian shale has been associated with existing localized fold/fault systems. Drilling activity appears to concentrate around structures created as a result of major basement tectonic activity.
The purpose of this study was to isolate the effects of stimualtion practices from the background effects of geology and differential reservoir depletion rates. By recognizing these sources of variability, comparison of well productivity for the various stimulation practices productivity for the various stimulation practices was made using standard statistical inference techniques.
The results of this study indicate that larger stimulation treatments, either by explosive shooting or hydraulic fracturing, have not generated incremental improvements in well productivity on a regular basis. Group of productivity on a regular basis. Group of post-1975 wells were analyzed to limit the time post-1975 wells were analyzed to limit the time dependant effects of reservoir depletion. Results from this group indicated natural completions, at a statistically significant level. exhibited greater productivity as compared to that of nitrogen productivity as compared to that of nitrogen fractured or shot wells. In evaluating the more modern practice of hydraulic fracturing, the more fractured wells exhibited significantly greater productivity than comparable wells stimulated by productivity than comparable wells stimulated by explosive shooting.
The Eastern Devonian shales, located in the west central part of the Appalachian basin, have produced over 2.7 trillion cubic feet [ 76.5 Gm-3] produced over 2.7 trillion cubic feet [ 76.5 Gm-3] of natural gas. Currently, there are over 9,600 producing Devonian shale wells in this part of the producing Devonian shale wells in this part of the basin. The economical development of this resource often depends on locating wells in areas with significant natural fractures.