Wettability alteration in shale formations can be an important factor in improving the performance of hydraulic fracturing treatments. The use of surfactants in the frac fluid, at proper concentrations, has shown to change wettability in Unconventional Liquid Reservoirs (ULR) favoring the process of imbibition. This study evaluates and compares the efficiency of anionic and nonionic surfactants in recovering hydrocarbons in carbonate and siliceous preserved side-wall core. The techniques developed also open the door for investigation of low concentration surfactants for enhanced oil recovery (EOR) in ULR. Contact angle (CA) experiments were performed, using the captive bubble method, to measure the magnitude of wettability alteration on intermediate to oil-wet ULR core at reservoir temperature (165 °F). Different types of anionic and nonionic surfactants at field concentrations were used. The results showed that all surfactants lower the CA at the concentration tested. However, anionic surfactants showed better results as observed by lower contact angles. IFT measurements were also performed, using the pendant drop and spinning drop methods, at reservoir temperature using reservoir crude oil and anionic and nonionic surfactants at the same concentrations. The IFT reduction was similar for each type of surfactant compared to regular frac fluid without any surfactant, but anionic surfactant showed slightly better capability of reducing IFT than nonionic surfactants. Computed tomography (CT) scan methods were used to gauge the performance of these surfactants in improving oil recovery. The magnitude of penetration or imbibition into artificially-fractured ULR cores was studied for both anionic and nonionic surfactants. Frac fluids containing surfactants were mixed with a dopant salt to trace the movement of these fluids and measure the penetration numerically. Both, anionic and nonionic, surfactants have higher penetration magnitudes compared to slick water without surfactant. However, anionic surfactants displaced a higher observable amount of liquid hydrocarbon from the shale cores. This observation agrees qualitatively with the results observed in the CA experiments where anionic surfactants showed the lowest contact angles. From the results obtained, it can be concluded that anionic surfactants alter wettability in these ULR core, giving lower CA, better spontaneous imbibition and higher oil recovery than nonionic surfactants. These observed wettability changes induced by surfactants mixed in the frac fluids can improve matrix penetration with spontaneous imbibition which opens further discussions for EOR potential in shale formations.

Improving the economics of the production and development of an unconventional reservoir system is a key to meeting increased demand for hydrocarbons in the near future. In general, reservoir development is vastly assisted by using hard-computing models to evaluate the potential of the formation. These models have been used to identify infill drilling locations and forecast production. However, preparing the simulation models for discontinuous tight oil reservoir systems poses a challenge with hard-computing protocols. This paper discusses a methodology developed to depict the production characteristics of a reservoir via the geological properties of the reservoir. The methodology discussed in the paper is time efficient and is proven to generate effective results. The methodology discussed in the paper utilizes Artificial Neural Networks (ANN) to map the existing complex relationships between seismic data, well logs, completion parameters and production characteristics. ANNs developed in this work are used to forecast oil, water and gas cumulative production for a two year period. The results obtained are also extended to identify potential infill drilling locations. This work enables the practicing engineer and the geoscientist to analyze an entire reservoir in a time efficient manner. The workflow is demonstrated on a discontinuous tight oil reservoir located in West Texas. The results discussed in the paper show the robust nature of the methodology. The workflow also helps in improving the resolution of the production surfaces which help in identifying productive, yet undrilled, locations in the reservoir. The production surface for the entire field is forecasted within a one minute time frame (~6600 locations). The method developed will help in avoiding low producing wells prior to drilling, and thus, is expected to help in the economic development of complex tight oil reservoirs.

Abstract Contractional natural fractures and slot porosity play and will continue to play an important role in commercial gas production from tight sands. The process that leads to these types of porosities starts with deposition of sand grains. As the grains get progressively buried inelastically the net stress increases continuously. Eventually the sand grains reach their maximum depth of burial and at this stage the vast majority of the porosity and permeability has been destroyed. Uplift leads to a cooling effect and thermo-elastic stresses that create contractional fractures and slot porosity. Throughout these processes the sand grains get deformed and as a result there are continuous variations in volumes and areas of pendular rings, which lead to variations in porosities, permeabilities and water saturations. This paper discusses models that can be used for estimating these variations for zero and non-zero contact angles in tight gas sands. The subject is significant because historically oil and gas companies have gone, rightly, after tectonic fractures associated with folding and faulting in tight gas sands. The present work discusses a different possibility as the contractional fractures discussed above are not restricted to areas dominated by major tectonic events. Introduction The term 'slot porosity' was introduced recently in the petroleum engineering literature (Aguilera, 2008) although it has been used in the past sporadically in geosciences (Shanley et al, 2004). Also in geosciences it has been referred to as 'tabular' porosity (Byrnes et al., 2006). This type of porosity can be explained as a result of cooling (for example due to uplifting), desiccation of sedimentary rock or shales that loose water. A fracture is defined as a macroscopic planar discontinuity that results from stresses that exceed the rupture strength of the rock (Stearns et al., 1972; Nelson, 1985; Aguilera, 1995). A naturally fractured reservoir contains fractures created by nature due to stress concentrations or perturbations associated with local deformation. These natural fractures can have a positive or negative effect on fluid flow. In the case of tight gas sands these natural fractures nearly always have a positive effect on fluid flow. Paleo-stresses are responsible for the creation on natural fractures found today in tight gas sands. In-situ stresses, i.e., contemporary stresses affect the way in which those natural fractures perform today. Both in-situ stresses and natural fractures (paleo-stresses) affect the results of hydraulic fracturing jobs. The orientations of paleo-stresses and stress magnitudes can change over time and are not necessarily the same as the orientations and magnitudes of contemporary in-situ stresses.

Abstract This paper presents a work-flow process to describe and characterize tight gas sands. The ultimate objective of this work-flow is to provide a consistent methodology to systematically integrate both large-scale geologic elements and small-scale rock petrology with the physical rock properties for low-permeability sandstone reservoirs. To that end, our work-flow integrates multiple data evaluation techniques and multiple data scales using a core-based rock typing approach that is designed to capture rock properties characteristic of tight gas sands. Fundamental to this process model are identification and comparison of three different rock types — depositional, petrographic, and hydraulic. These rock types are defined as: Depositional — These are rock types that are derived from core-based descriptions of genetic units which are defined as collections of rocks grouped according to similarities in composition, texture, sedimentary structure, and stratigraphic sequence as influenced by the depositional environment. These rock types represent original large-scale rock properties present at deposition. Petrographic — These are rock types which are also described within the context of the geological framework, but the rock type criteria are based on pore-scale, microscopic imaging of the current pore structure — as well as the rock texture and composition, clay mineralogy, and diagenesis. Hydraulic — These are rock types that are also defined at the pore scale, but in this case we define "hydraulic" rock types as those that quantify the physical flow and storage properties of the rock relative to the native fluid(s) — as controlled by the dimensions, geometry, and distribution of the current pore and pore throat structure. Each rock type represents different physical and chemical processes affecting rock properties during the depositional and paragenetic cycles. Since most tight gas sands have been subjected to post-depositional diagenesis, a comparison of all three rock types will allow us to assess the impact of diagenesis on rock properties. If diagenesis is minor, the depositional environment (and depositional rock types) as well as the expected rock properties derived from those depositional conditions will be good predictors of rock quality. However, if the reservoir rock has been subjected to significant diagenesis, the original rock properties present at deposition will be quite different than the current properties. More specifically, use of the depositional environment and the associated rock types (in isolation) to guide field development activities may result in ineffective exploitation. Introduction Unconventional natural gas resources — tight gas sands, naturally-fractured gas shales, and coalbed methane reservoirs — comprise a significant percentage of the North American natural gas resource base and these systems represent an important source for future reserve growth and production. Similar to conventional hydrocarbon systems, unconventional gas reservoirs are characterized by complex geological and petrophysical systems as well as heterogeneities — at all scales. However, unlike conventional reservoirs, unconventional gas reservoirs typically exhibit gas storage and flow characteristics which are uniquely tied to geology — deposition and diagenetic processes. As a result, effective resource exploitation requires a comprehensive reservoir description and characterization program to quantify gas-in-place and to identify those reservoir properties which control production. Although many unconventional natural gas resources are characterized by low permeabilities, this paper addresses only low-permeability sandstone reservoirs, i.e., tight gas sands.

Abstract The massively stacked, lenticular sands of the Piceance, Green River, and Uinta basins have been judged, by the USGS, to be the largest undeveloped gas resource in the U.S. Past attempts to produce natural gas from these formations have been, in the main, disappointing. Six advances in technology offer potential for unlocking a portion of these gas resources and turning them into near-term, low cost gas reserves: – Natural fracture detection to find "sweet spots", – Advanced well log analysis to target productive pay, – Advanced well completion and stimulation to connect pay to the wellbore, – Intensive infill development for efficient drainage, – Recompletion of old wells to add reserves, and – Best practices to reduce costs. Field case studies at Rulison Field, Piceance Basin show how each of these technologies have been applied. The package of technologies presented in this paper may help producers develop stacked, lenticular sands in other basins. This assessment is part of a Gas Research Institute (GRI) research project examining technology improvements for lowering the costs of future gas supplies. Introduction Improved well siting and completion practices have revived a previously discovered, but commercially condemned tight gas play in the southern Piceance Basin of Colorado. Here, the target is the massively stacked, lenticular sands (and coals) of the Mesaverde Group, Williams Fork Formation stretching upward for several thousand feet from the top of the Rollins, through the Cameo coal and sand interval, to the gas and water transition zone below the Wasatch Formation. The bulk of the activity has been at the Rulison and Grand Valley/Parachute fields, where Barrett Resources is drilling, infilling and recompleting wells, and at Mamm Creek where Snyder Oil is active. Chevron, Occidental, and the DOE/NOSR are other participants in this gas play. The Williams Fork lenticular sands gas play was discovered in 1959 by the Juhan #1 Fee well. The well had strong early gas flow rates giving rise to high expectations. When subsequent wells showed poor reserves (0.2 to 0.5 Bcf per well), this gas play was relegated to a low productivity, high cost natural gas resource. Still, these lenticular tight sands were judged to hold massive gas resources in-place of 100 to 300 Tcf, as estimated by the National Petroleum Council and the USGS. Four events have combined to revive this gas play and make it economically competitive, even during the past several years of low gas prices: Improved well siting and well completion practices have significantly improved the productivity of this gas play. P. 505

Abstract A detailed investigation of borehole instability in the Foothills region of Northeastern British Columbia, Canada is described. Costly problems due to hole collapse have been experienced during the drilling of deviated wells through dipping, fissile shales in the region. An integrated field and laboratory research study of the Fernie Formation was undertaken including the cutting of an 18 m core, petrophysical and rock mechanics testing, and borehole stability modelling. Key insights into the mechanisms of instability have been gained from the logging of discontinuities in the core and ultrasonic borehole imagery acquired in the well. Triaxial strength measurements are used to model the development of yielding in the rock mass and along bedding plane parallel fractures using 3D geomechanical software. Recommendations for selecting appropriate drilling fluids, planning hole trajectories and reducing problem time in similar settings are provided. Introduction Borehole instability related problems often arise when drilling weak, fissile shales in the Foothills region of Western Canada. Total or partial hole collapse can occur rapidly or over an extended period of time resulting in stuck pipe, poor hole cleaning, poor logging conditions and excessive cement and mud volumes. A limited number of case histories describing borehole instability in Western Canada have been published, although there is very little written about Foothills drilling problems. Recently, Last et al described an integrated effort to evaluate and manage borehole instability in the Cusiana field of Columbia, which is located in a similar thrust belt. Shell Canada has historically been an active gas explorer and producer from the Foothills region of Western Canada. A review of its drilling costs in the late 1980's revealed that 56% of all drilling problem costs, or 12% of total drilling costs were directly or indirectly related to borehole instability. A multidisciplinary team was formed to investigate the underlying causes of the problems and to develop operational procedures to reduce or eliminate these costs. Several studies were undertaken including: – FMI and FMS studies of fractured Fernie shale sections – Area studies of caliper logs and their relationship to drilling problem time – In-situ stress evaluations using log-based techniques – Rock mechanical property testing – Geomechanical modelling of hole collapse and enlargement processes – On-site monitoring of hole enlargement including the continuous measurement of cavings Learnings from this team were conveyed to operational personnel through presentations, workshops, computer programs and planning studies for individual wells. Unfortunately, mechanistic predictive modelling has been hampered by the lack of good quality, representative rock strength and stress data. This paper focuses on an integrated investigation in the Boulder field of Northeastern British Columbia. Borehole collapse problems had been experienced by Shell and other operators in the vicinity, especially where long sections of dipping, fissile shales of the Fernie Formation were encountered. Severe borehole enlargement occurred in the two previous Boulder wells, with related problem time and poor logging conditions. The structural complexity of the region and the often uncertain geology complicated well planning and occasionally resulted in the need for wells to be sidetracked. In 1994 Shell Canada took advantage of the opportunity to obtain logs and a shale core from the problematic Fernie Formation in order to improve its understanding of borehole instability. P. 535

SPE Members Abstract This paper contrasts the results of centrifuge capillary pressure measurements determined at ambient and overburden pressures. The effects of centrifugal forces and overburden pressure on the integrity of well consolidated uniform rock samples are minimal. However, unconsolidated sands, poorly consolidated sandstones, and friable cores are susceptible to deformation and grain rearrangement, while vuggy cores are susceptible to surface drainage. The severity of these occurrences, which depend on sample lithology and the magnitude of centrifugal forces, can be minimized or avoided by proper jacketing and application of overburden pressure. Introduction The theory, measurement and application of capillary pressure concepts have received extensive attention in the petroleum industry literature. These applications range from the fundamental use of drainage or imbibition capillary pressure for determination of fluid distribution, pore size distribution, and absolute permeability, to the more complex issues of relative permeability, wettability, oil recovery, and the assessment of formation damage and stimulation. The development and application of the general concepts of capillarity were introduced by Leverett in 1941. Since introduction, three methods have evolved as the most widely used means of obtaining capillary pressure data. These are the centrifuge, porous plate, and mercury injection. Hassler and Brunner's pioneering work introduced the centrifuge technique for determining capillary pressure and the methodology for converting the average saturation to the end-face saturation. Capillary pressure measurements in the centrifuge have historically been performed on "unjacketed" samples without overburden pressure. O'meara et al. stated that "there are several reasons for jacketing cores: to prevent evaporative losses, to minimize excess fluids from collecting on the outside of the core, and to safeguard core integrity by protecting the sides and edges". Omoregie recommended that for unconsolidated samples, "application of overburden pressure with a Hassler-cell or by potting in acrylic or other suitable material is preferred", and suggested that "more tests be done to make the results of this overburden pressure effect quantitatively definitive". This paper presents the results of centrifuge capillary pressure measurements determined at overburden pressure conditions. Although the Hassler and Brunner saturation conversion method was used for this work, different saturation conversion methods can be used without altering the results of this study. Fundamentally, major factors affecting capillary pressure behavior are wettability, interfacial tension, pore size and distribution, saturation history, and fluid density difference. This work focuses on the effects of changes in pore size and distribution on capillary, pressure keeping other factors constant. P. 107^

Northrop, D.A., Sandia Natl. Laboratories SPE Member Abstract Insights have been gained into natural gas production from low permeability sandstone reservoirs in the western United States as a result of the U.S. Department of Energy's Multiwell Experiment (MWX). Three wells, between 110 and 215 ft (34-66 m) apart at depth, have been drilled at a site southwest of Rifle, Colorado, in the Piceance Basin, where the Cretaceous-age Mesaverde lies at a depth of 4,000 to 8,250 ft (1220-2520 m). Activities have been conducted in the lowermost Corcoran-Cozzette marine sandstones and in the overlying paludal, coastal, and fluvial nonmarine intervals. Insights include: the depositional environment controls reservoir morphology, size, internal structure, and natural fracturing; thus, it must be discerned in order to optimize completions and interpret reservoir performance; natural fractures, even if small and mineralized, are the dominant production mechanism in these, and probably most other, very tight reservoirs; breakdowns and extended cleanup and test times are required for accurate reservoir assessment; effectiveness of hydraulic fracturing appears limited by an anisotropic natural fracture system, high fracturing pressures, accelerated leakoff, and damage to the natural fracture system; and in situ stress behavior varies with depth and lithology, is complex, and significantly affects stimulation and gas production. Introduction New and improved technology is required to enhance natural gas production from the low permeability sandstone reservoirs of the United States. This is a large potential resource with an estimated maximum recoverable resource of over 600 TCF (17 Gm). The U.S. Government's efforts to stimulate production from these reservoirs began in the mid-1960s. The early work evaluated the use of nuclear explosives for fracturing, but this technique was abandoned in 1973. Efforts then focused upon massive hydraulic fracturing and several government-industry projects were conducted. The results were disappointing and did not result in either an improved technology or confident, widespread production. The basic shortcoming was that these past field tests provided insufficient data to define the critical factors affecting gas production from this resource. The U.S. Department of Energy's Multiwell Experiment (MWX) was conceived as a field laboratory to obtain sufficient information on the geologic and technical aspects to unlock this resource. A key feature of MWX is three wells Spaced between 110 and 215 ft (34-66 m) apart. Detailed core, log and well test data from such close spacings provide a detailed characterization of the reservoir. Interference and tracer tests, as well as the use of fracture diagnostics in offset wells, give additional, out-of-the-ordinary information on stimulation and production. A second key is the synergism resulting from a broad spectrum of activities: geophysical surveys, sedimentological studies. core and lo analyses, well testing, in situ stress determinations, stimulation, fracture diagnostics and reservoir analyses. All these activities are further enhanced by the closely spaced wells. Thus, the Multiwell Experiment provides a unique opportunity for understanding and enhancing production from tight gas reservoirs. Further discussion of the rationale, plans, objectives and activities of MWX can be found in References 2 to 5. The purpose of this paper is to highlight some of the insights into the production of natural gas from the low permeability sandstone reservoirs, typical of the western United States, that have been gained as a result of the Multiwell Experiment. Various people at Sandia National Laboratories and CER Corporation have been principal investigators in MWX. Extensive reference will be made to their results from this unique project. P. 25^

Abstract The Pictured Cliffs Sandstone is a large, low permeability, gas producing reservoir. It is considered to belong to a class of reservoirs known as volumetric or bounded cylindrical reservoirs where the wells are surrounded by impermeable (or semi-permeable) boundaries. In the Pictured Cliffs reservoir, the advancement of the drainage radius is shown to reach its maximum limit at the end of the transient period of the pressure decline versus time curve. Introduction The Pictured Cliffs Sandstone is in the southeastern part of the San Juan Basin located in northwestern New Mexico (Figure 1). The study area (Figure 2) was selected on the basis of the availability of production and pressure histories for the wells therein and includes sections 9 and 10, T. 25 N., R. 2. W., New Mexico Principal Meridian. The study analyzes the production and pressure decline histories of the Pictured Cliffs wells (Table 1) to ascertain whether the pressure decline data can be used to determine the drainage radius pressure decline data can be used to determine the drainage radius of a well in a low permeability gas reservoir. Production-pressure decline versus time curves, material balance, and volumetric equations are utilized in determining the extent of the drainage radius. GEOLOGIC SETTING The San Juan Basin, located in northwestern New Mexico and southwestern Colorado, is roughly a circular area in which the sedimentary beds dip to a low point in the northeastern part of the basin. The Pictured Cliffs Sandstone in the San Juan Basin is of Cretaceous age and was deposited during the final regression of the Late Cretaceous sea. A structure contour map on the top of the Pictured Cliffs Sandstone was prepared using electric well logs from wells (Table 1) in the study area (Figure 2). The structure contour map shows that, locally, the Pictured Cliffs Sandstone dips 1 degree to the West. The Pictured Cliffs gas production from wells in the San Juan Basin is from three intervals. For the purposes of this study, the interval from which the wells in the study area produce is designated zone "A". This zone is a blanket-type sandstone bed and has a uniform thickness within the study area (Figure 3). Lithologic characteristics (mineralogic composition, grain size, clay content, texture, matrix, etc.), as described in published literature and the petrophysical properties (porosity, published literature and the petrophysical properties (porosity, water saturation, radioactivity, resistivity and lithology), as demonstrated by electric logs from wells in the study area, strongly suggest that Pictured Cliffs zone "A" is a low permeability gas reservoir. P. 257

Abstract Research efforts undertaken by the Morgantown Energy Technology Center, Department of Energy, have focused on the geologic assessment of gas hydrate deposits existing in two different settings (onshore and offshore). Preliminary assessments have been completed for the North slope of Alaska and the offshore east coast of the United States. Specific sites studied in the onshore setting were the Point Barrow, Kuparuk River, Prudhoe Bay, Cape Simpson, Cape Thompson, and Umiat areas of Alaska. The specific site for the offshore setting was the Blake-Bahama Outer Ridge area of the western Atlantic. This study demonstrates the use of geophysical, geological, and geochemical techniques and data to locate and evaluate the potential gas hydrate resource of these two settings. Introduction This study was initiated to evaluate the geologic factors that control the formation and detection of gas-hydrates within onshore and offshore environments. This study focused on two areas where gas hydrates are known to occur: the Alaskan North Slope (onshore) and the U.S. east coast continental margins (offshore). It is known that gas hydrates are a type of inclusion compound, or clathrate, formed as a solid, ice-like mixture of gas and water in which gas molecules are trapped within a framework of water molecules (see Figure 1). Water and natural gas, under certain conditions of temperature and pressure, can form naturally occurring gas hydrates in sediments underlying ocean basins and within or adjacent to permafrost regions. Because gas hydrates form under conditions of relatively low temperatures and high pressures, two opposing factors control the formation and distribution of gas hydrates in the Earth, given sufficient quantities of gas and water. The first is the geothermal gradient, or temperature increase associated with increasing crustal depth. Average continental gradients are generally 2 to 3 °C/100 m, while offshore geothermal gradients average 3.6 °C/100 m in the western Atlantic. Because hydrates are generally stable under conditions of relatively low temperatures, the geothermal gradient limits hydrate formation and existence to relatively shallow, cooler regions of the Earth's crust. The second factor that controls the distribution of hydrate regimes is the pressure gradient, or pressure increase associated with increasing water and/or crustal depth. Average pressure gradients are generally 10.1 kPa/m. Because hydrates are generally stable under conditions of relatively high pressures, the pressure gradient limits hydrate formation and existence to depths below 300 m in continental areas and 500 m (minimum water depth) in offshore areas. Therefore, because of the opposing factors of pressure and temperature, there is a defined region where hydrates are stable called the hydrate stability zone (HSZ) (see Figure 2). The source of methane for gas-hydrate formation may be either biogenic or thermogenic. Biogenic methane results from the microbial breakdown of organic matter in shallow sediment; thermogenic methane comes from the thermal alteration of organic matter in sediment at depth. Because gas hydrates occur in shallow sediment, biogenic sources are often indicated, especially for gas hydrates of outer continental margins (Kvenvolden and Barnard, 1983). Where gas migration pathways are available from deep within the sedimentary section, thermogenic gas may also form hydrates.

Abstract Deep Source Gas research is focused on the hypothesis that natural gas is generated in sediments carried to great depths at convergent plate boundaries in the earth's crust. These deeply emplaced plate boundaries in the earth's crust. These deeply emplaced sediments may source gas to shallower, drillable traps through deep fracture systems. Many areas of North America are believed to have experienced plate tectonic convergence. The western Cordilleran geologic province in particular appears to have thrust fault structures (associated with subduction and abduction) that enabled deep emplacement of hydrocarbon-generating sediments during more recent geologic ages (during the last 180 million years). The specific area of interest in this province encompasses approximately 1.5 million square miles of the western U.S. (including Alaska) and Canada; other portions of this same province extend southward into Mexico and Central and South America. The ongoing research consists of basic studies of hydrocarbon generation, stability, and preservation at depths in excess of 30,000 feet in addition to a comprehensive evaluation of the geologic structures, stratigraphy, and geochemistry of the above region. Results to date include geologic and geophysical evidence of deeply emplaced sedimentary rock units at depths exceeding 30,000 feet in western Washington and south central Alaska, a new methodology for verifying deep methane stability via fluid inclusion studies, and a preliminary gas resource estimate of 3,000 Tcf. If only a fraction of the gas thought to exist is found to be recoverable, it could have a profound influence upon the international energy industry. Introduction There is general agreement that natural gas will continue to be an important alternative to other energy sources. Since 1976, the U.S. Department of Energy (DOE), Morgantown Energy Technology Center (METC) has been involved in unconventional gas recovery (UGR) research to characterize this resource and to enable the exploitation of natural gas from reservoirs that would otherwise be considered economically unrecoverable. The research has focused on low porosity, low permeability, or otherwise undeveloped resources whose sources and reservoirs are at conventional depths (15,000 feet). In 1982, a new effort emerged that was a natural outgrowth of DOE/METC's experience in UGR research. Natural gas resources are being investigated that require long-term, high-risk research and development, but offer a significant potential payoff. The level of risk is such that little or no private sector research is envisioned for the near future. A workshop held in 1982 in Morgantown, West Virginia, addressed the subject of deep source gas from the perspective of three separate emplacement concepts: abiogenic gas, subducted organic-origin gas, and deep intracratonic sedimentary basin gas. Following the workshop, it was decided that METC research of deep source gas would focus on the subducted, organic-origin gas concept. DOE/METC will continue to monitor the abiogenic gas research supported by the Gas Research Institute (GRI). The existence of methane or methane-generating source rocks at great depth in the earth's interior remains theoretical. If the existence of such gas was merited, it could radically influence the methods used to explore for new supplies. If even a fraction of the deep gas thought to exist proves to be recoverable, it could have a profound influence upon the international energy industry. The nature of the deep source gas resource has yet to be identified. P. 685

Abstract Middle and Upper Devonian subsurface rocks in six counties in northwestern West Virginia can be divided into formal units of organic-rich black shales overlain by inorganic gray and greenish-gray shales. The section thickens west-to-east from 2,000 to 4,000 feet, including some fine sandstones and siltstones in the upper part. Drilling since 1980 has discovered several productive intervals in this thick sequence. Generally, younger siltstones and shales down to the Huron Shale produce oil and gas; below the Huron, gas dominates. In map view, three broad oil and gas plays can be related to facies changes and to the Burning Springs Anticline. West of this structure, both organic-rich and inorganic shales produce gas; on and immediately east of the anticline, transitional facies (including black and gray shales, and younger siltstones) produce oil and gas; and farther east, siltstone bundles produce gas and some oil. Thus, completion-zone thickness ranges between 30-2,000 feet, with varied completion techniques. Under a current Gas Research Institute contract, we are seeking possible relations among stratigraphy, completion intervals and techniques, initial potential (IP), and production. Preliminary studies in three counties indicate that gas IPs are highest when three or more formations are completed using nitrogen-fracturing. In one first year production study, the average shale oil well east of the Burning Springs Anticline is short-lived, declining by 95% of IP after one year before leveling off. A similar first year production study for 3 adjacent counties indicated less rapid production study for 3 adjacent counties indicated less rapid decline of oil wells located along the Burning Springs Anticline. Introduction Historically, gas producers in West Virginia have drilled Devonian shale wells in areas of known production, all in the western one-third of the State. In that area, the shale section is relatively thin, between 1,000 and 2,500 ft., and consists of two main lithologies: gray shale and black shale. Production generally was established by shooting either the upper black shale section (Huron) or the Huron and lower (Rhinestreet) black shales, plus the intervening gray shale. Recently, however, deeper-pool tests in low Mississippian fields over and near the Hiring Springs Anticline have discovered both gas and oil at several depths in the shale section, in several counties (Figure 1). In this newly productive area, the shale section is thicker, between 2,000 and 4,000 ft., and consists of interbedded lithologies that include fine-grained sandstones, siltstones, and both gray and black shales. Furthermore, production has been established by completing various combinations of lithologies over intervals ranging from 30 to 2,000 ft., utilizing several completion techniques, including nitrogen, carbon dioxide, and foam fracs. As measured by initial potentials (IPs) reported on completion forms, results range from poor to exceptional. The broad differences in number of formations completed, thickness of zones completed, completion technique, and results, lead to some questioned: What zones and what techniques yield the best wells? Also, because of the vast number of wells that have been drilled and completed in the area, how can we best handle these diverse data for a large number of wells. To answer these questions, a three-county area of high current activity was selected to study the relations among stratigraphy, completion techniques, and initial potential. P. 173

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

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 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 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 gram—cc/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 basins––toward the same center. P. 151

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

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 Vast quantities of natural gas exist as solid hydrates in the world's permafrost and deep sea environments. Russian experts estimate potential permafrost and deep sea environments. Russian experts estimate potential resources in excess of 10 7 TCF natural gas. Geophysical inference and direct sampling seem to substantiate the existence of hydrates where thermodynamic conditions are favorable. Their ubiquity provides an interesting link to another unconventional hypothesis of unconventional gas supply, namely the abiogenic origin of deep earth gas. A method to evaluate the abiogenic hypothesis is to compare the isotopic, trace element and compositional signature of hydrate samples from deep lake sediments in basins over crystalline basement rocks (Lake Superior) and over sedimentary rocks in connection with a producing petroliferous province (Lake Michigan). Because of the complex relations between in situ dissociation and production of the free gas phase actual extraction methods will be technically complicated. A method to circulate warm surface water through a set of injection and withdrawal wells in deep sea hydrate deposits promises some advantages over conventional offshore drilling practices. promises some advantages over conventional offshore drilling practices. Even if only a fraction of the claimed hydrate resources are accessible and producible the absolute amount is still very large compared to all other producible the absolute amount is still very large compared to all other conventional and unconventional gas resources. UNCONVENTIONAL GAS SOURCES AND ENERGY SUPPLY In its quest to augment available fossil energy reserves in general and to lessen energy dependency from outside sources the U.S. oil and gas industry is intensifying and extending its exploration and development efforts for new sources of oil and gas. This activity concentrates first on the finding of new reservoirs of conventional hydrocarbons and developing new, more efficient production and recovery techniques. At the same time this search is extended to so-called unconventional supplies more specifically to unconventional gas. These gas sources are: tight gas formations (especially Western Sands); mineable and unmineable methane rich coal beds; gas bearing Devonian shales (especially in the Appalachian basin); geothermal-geopressured dissolved methane in formation waters (Gulf Coast area); methane hydrate sediments. Of these the first four have received most of the official attention in various studies of the National Petroleum Council. Petroleum Council. In the conventional analysis of unconventional gas the greatest potential for future supply is assigned to tight gas reservoirs, furnishing potential for future supply is assigned to tight gas reservoirs, furnishing 30 to 50% of the demand in the next century. Baker has based his definition of unconventional gas on a purely economic context. "It is located in a reservoir with properties that prevent its recovery by conventional practice at current prices." Their geologic setting remains quite ordinary. In the case of the tight sands a distribution plot of permeability of U.S. reservoirs versus percent reservoir volume on a permeability of U.S. reservoirs versus percent reservoir volume on a log-probability plot produces a smooth curve. Conventional gas reservoirs are those with permeabilities of one millidarcy and more, unconventional gas reservoirs have less than one millidarcy permeability. This definition may be useful, but it is nevertheless arbitrary and masks the fact that the transition from conventional to unconventional gas is gradual for this particular example. particular example. This can be more clearly demonstrated with a modified McKelvey diagram for the definition of reserves and resources applied to natural gas as shown in Figure 1. It bases its classification of resources as proven, probable, and speculative on the basis of certainty of identification and probable, and speculative on the basis of certainty of identification and location, and as feasible, marginal, and submarginal on the state of technological feasibility of extraction and economic feasibility. In the upper left hand corner we have a field of proven reserves—essentially congruent with conventional sources. As one moves outwards from this field reserves become less certain as conditional hypothetical and finally speculative resources. p. 417

Abstract In order to determine the coal bed methane potential of the Raton basin, Colorado Geological Survey potential of the Raton basin, Colorado Geological Survey personnel studied the geography, the geology, the personnel studied the geography, the geology, the history of oil and gas exploration, and the coal resources and past production in the Raton coal region. Data gathered during study of the above disciplines, along with direct measurements of the coals' gas content, can be used to estimate the methane potential of the Raton basin. Introduction Coal has been mined commercially in the Colorado portion of the Raton basin since 18701; reports of portion of the Raton basin since 18701; reports of methane gas occurrences in the coal mines date back to the same period. Oil and gas exploration in the region began late in the last century. Explorationists encountered methane gas as they drilled through coal zones; they even tested some coal beds. Today coal mines, coal core holes, and oil and gas tests are still encountering large amounts of coal-derived methane. If the amount and source of this gas could be better defined, possible coal mining hazards could be predicted and an untapped gas source utilized. In 1975, the U.S. Bureau of Mines provided the Colorado Geological Survey with a grant to gather data on the methane potential of the coal beds of Colorado. During this grant, Survey geologists located 32 historically gassy mines and recorded methane emission rates from operating mines. In addition, Survey geologists began using the U.S. Bureau of Mines "direct method" of desorbing (or measuring the gas emitted by) fresh coal core samples to determine the total gas content of a coal. Today, this research continuous under two grants a U.S. Department of Energy Grant entitled "Evaluation of the Methane Potential of Unmined/Unminable Coalbeds in Colorado" and a Colorado Oil and Gas Conservation Commission grant entitled "Conservation of Methane from Mined/Minable Gaseous Coal Beds". Forty one coal core samples from the Raton coal region alone, have or are being desorbed. In addition, the geography, geology, oil and gas resources, and coal resources of the region are being studied to provide a framework for the methane data. GEOGRAPHY The Raton basin is a 241 × 193 Rm (150 × 120 mi.) north-south trending structural basin in southeastern Colorado and northeastern New Mexico (Fig. 1). The area of the Colorado portion of the basin is approximately 12,950 km2 (5000 mi.2). The basin is bounded by the Sangre de Cristo Mountains to the west, the Wet Mountains and the Apishapa uplift to the north and northeast, and the Sierra Grande-Las Animas arch to the east and southeast. The coal bearing region in Colorado is a 2850 km2 (1100 mi.2) area in Las Animas and Huerfano Counties. The region is a plateau within the basin edged by the cliff-forming outcrop of the Trinidad sandstone. The elevation of the coal region ranges from 2130 m (7000 ft) in the east to 2740 m (9000 ft) in the west; the highest point is West Spanish Peak at 4152.29 m (13,623 ft). The plateau is dissected by the Purgatoire, Huerfano, Cuchara, and Apishapa Rivers (all Purgatoire, Huerfano, Cuchara, and Apishapa Rivers (all eastward draining tributaries of the Arkansas River) (Fig. 1). The largest towns of the region occur where these rivers flow onto the plains: Trinidad (population 9901) on the Purgatoire, Walsenburg (population 4329) on the Cuchara, and Aquilar (population 699) on the Apishapa. Important land uses include grazing cattle and sheep, dry farming (at intermediate elevations), irrigation farming (along larger streams), lumbering (in the mountains), and coal mining. The climate of the coal region is dependent on the elevation and ranges from semiarid in the plains to subhumid in the mountains. Most precipatation occurs as thundershowers from April through September; there is a dry spell in June. Vegetation is also elevation dependent. Eighty percent of the area is in the foothills vegetation percent of the area is in the foothills vegetation zone of open coniferous forests and grasslands. P. 43

Gas Technology Symposium, 17–18 April, Shreveport, Louisiana Abstract A brief and basic discussion of the theory of radioactivity logging along with types of instrumentation now in use explain how gas bearing zones are detectable in cased hole or open hole by use of radioactivity logs. Numerous examples of the successful use of single and multispaced neutron logs are presented. Also included are examples of the detection of gas, distillate, oil-, and water-bearing sands by proper interpretation of radioactivity logs. A new technique for determining the L.P.G.-Brine interface in an L.P.G. storage cavity is discussed. A new technique, developed in Venezuela for determining the point of gas entry into a bore hole is discussed. A great deal has been written concerning the theory of radioactivity logging and to go into this subject deeply would be repetitious, however, to enter into a discussion of applications of this type of log it is necessary to briefly cover the fundamentals of theory and instrumentation. The gamma ray log is a measure of the natural radiation of formations. All earth formations contain radioactive elements, some more than others. Figure 1is a table of natural radio-elements showing the progression down the scale with the accompanying emission of radioactivity at the various stages. There are three families of elements which are radioactive. These are the Uranium series, the Actino-Uranium series and the Thorium series. This chart clearly shows that an atom of uranium, in progressing through the various stages, will be at one stage ionium, then radium, then radon, etc., and end the progression as non-radioactive lead. At almost every stage of this progression some form of radiation is given off. The radiation will be an alpha particle, a beta particle or a gamma ray. Although each moves with very high velocity, a thin sheet of bond paper is sufficient barrier to stop an alpha particle. The beta particle has more energy than the alpha, however, several sheets of cardboard will successfully shield one from the radiation of betas. Gamma rays have the ability to penetrate 12 inches of steel or 8 inches of lead. From this it is easily seen that only gamma rays may be detected with the instruments now in use because the instrument wall is sufficiently thick to shield out the alpha and beta particles. Furthermore the gamma ray has such great penetrating qualities that we may case a well with concentric pump liners and still obtain a formation gamma ray log. The neutron is very little more affected by casing so we may also obtain a neutron in the well cased with pump liners.