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Summary The purpose of this paper is to present practicing engineers and scientists with a new means of estimating the absolute surface roughness values, ε, and relative roughness, ε/d, which are specific to modern pipes with specialized internal finishes. Our research thrust has developed new relative-roughness-design equations, values, and derived charts. Currently, the friction-pressure losses in pipes are being evaluated by practicing engineers by use of Moody's relative-roughness chart (Szilas 1975; Economides et al. 1994). Moody (1944) prepared a relative-roughness chart for a number of common piping materials. Relative roughness provides a simple means for estimating friction factors to be used in computing the friction-pressure losses in piping systems. An accurate determination of the frictional fluid-pressure drop in pipes is required for design purposes. Currently, these newly developed pipes are used worldwide for various applications, and their surface-roughness values are needed to properly model the hydrodynamics (Farshad et al. 2001; Brown 1984). Recently, Farshad and Rieke (2005) published a new relative-roughness chart for the modern manufactured oil-country tubular goods (OCTG). Moody did not provide equations for his relative-roughness chart. Equations are the foundation for establishing such correlation charts. In our research, a new set of nonlinear mathematical models was successfully regressed and developed to accurately describe the log/log relationship between pipe diameter and relative roughness. In this paper we provide a set of new equations for our charts. The new equations developed can be used directly in computer models and simulators for frictional pressure-drop calculations.

Most commercial oil sands exhibit shale resistivity ratios (ratio of normal R shn to observed R sho ) of less than approximately 1.6 in adjacent shales and can be reached without an expensive string of protection pipe. On the other hand, some experts claim that “no commercial production is found when the shale resistivity ratio reaches and/or exceeds 3.5.” This statement, however, needs further investigation Such wells often are highly productive initially and are characterized by extremely fast pressure depletion. Based on extensive compaction studies of rocks, the authors argue that the latter is due to plastic deformation (irreversible compaction) in undercompacted overpressured rocks with increasing effective stress soon after production is initiated (or during well testing). Thus, well tests could be quite misleading, and many er roneously condemned overpressured reservoirs should be reexamined, reevaluated, and strategies be developed to recover the oil and gas from these stress-sensitive reservoirs.

Technology Today Series articles are general, descriptive representations that summarize the state of the art in an area of technology by describing recent developments for readers who are not specialists in the topics discussed. Written by individuals recognized as experts in the area, these articles provide key references to more definitive work and present specific details only to illustrate the technology. Purpose: to inform the general readership of recent advances in various areas of petroleum engineering. Abstract Since 1995, several petroleum companies have actively sponsored research on how internal-surface wall-roughness texture affects the flow of fluids in oil-country tubular goods (OCTGs). The research goal focuses on the development and application of new technologies in combating the effects of pipe corrosion, establishing new piping materials and coatings, increasing the ease of fluid flow in pipes, and validating such improvements. A result of the research is a newly developed surface-roughness correlation for modern pipes. Introduction Currently, one area of focus is on achieving infrastructure-cost reductions in the transport of gas and oil through pipelines. Profilometer technology is a good example of one such application that is being adapted from the metal fabrication/manufacturing industry to measure the internal-surface roughness of piping. Internal-surface roughness impedes the dynamic transfer of fluids and is a major factor in the optimization of production tubing and pipeline utilization. Corrosion creates scale and pits along the walls of the piping, which in turn impedes flow and creates a loss of pipewall integrity. Other irregularities result from cutting tools, chatter, abrasive cleaning and preening operations, plating, anodizing, and chemical milling during manufacturing. The roughness of a solid surface is defined as any departure of the actual surface from an ideal datum level known as the nominal level. Surface profiling gauges the ups and downs of a surface, which the human eye cannot discern. The method results in a quick and easy way of calculating the pipe's friction factor. This method is a major step forward in production-tubing and pipeline design. The elimination of expensive and time-consuming flow-loop testing is the most obvious advantage of this technology.

The purpose of this paper is to present petroleum and chemical engineers with a simple means of measuring or estimating the absolute surface roughness, ϵ, and relative roughness, ϵ/D, for internally coated pipes. Our research thrust is to develop new relative roughness charts along with corresponding mathematical equations for internally coated pipes. An integral part of the frictional pressure drop due to fluid flow in pipes involves the determination of absolute surface roughness and relative roughness. An accurate determination of the pressure drop due to fluid flow in oil and gas wells is required for optimizing oil and gas production design calculations. Some of these calculations include developing tubing programs to maximize well deliverability, wellbore flow performance, sizing surface flow lines, and designing artificial lift installations. Previous multiphase fluid flow laboratory and field tests, during the past 50 years, provided correlations for calculating pressure gradients in tubulars [Chem. Eng. Prog. 45(1) (1949) 39; Hetsroni, G., 1982. Handbook of Multiphase Systems, Hemisphere/McGraw Hill, 1174 pp.; Brown, K.E., 1984. The Technology of Artificial Methods, vol. 4, Penn Well Publishing, Tulsa, OK, 447 pp.; Tengesdal, J.O., 1998. Predictions of Flow Patterns, Pressure Drop, and Liquid Holdup in Vertical Upward Two-Phase Flow. MSc Thesis, The University of Tulsa, Tulsa, OK; Farshad, F., Garber, J.D., Polaki, V., 2000. Comprehensive model for predicting corrosion rates in gas wells containing CO2. Soc. Pet. Eng. Prod. Facil. 15(3), 183–190]. All the multiphase fluid flow correlations, used in production operations to calculate these pressure gradients and flow regimes, stem from the general energy balance equation and involves the determination of friction pressure losses. Still today, these friction losses only are being evaluated by practicing engineers using the Darcy–Weisbach equation, which involves the Moody friction factor, f [Szilas, A.P., 1975. Production and Transport of Oil and Gas. Elsevier Sci. Publ., Amsterdam, p. 630; Economides, M.J., Hill, D.A., Ehlig-Economides, C., 1994. Petroleum Production Systems, Prentice Hall, Englewood Cliffs, NJ, 611 pp.]. Moody [Trans. AME 66 (1944) 671] prepared a relative roughness chart for a number of common piping materials. This initial relative roughness correlation was based on experiments on pipes artificially roughened with sand grains. At that time, internally coated pipes were not invented. Hence, Moody did not provide the relative roughness for internally coated pipes. In addition, Moody did not perform a regression analysis of the data to generate functional forms of equations by relating roughness, ϵ/D, as a function of internal pipe diameter, D. Currently, internally coated pipes are being utilized worldwide in oil field production systems. Consequently, new absolute surface roughness and relative roughness values of internally coated pipes are needed to properly model the hydrodynamics [Brown, K.E., 1984. The Technology of Artificial Methods, vol. 4, Penn Well Publishing, Tulsa, OK, 447 pp.]. The new relative roughness plots developed for internally coated pipes are presented and show that the correlation fits between the commercial steel and drawn tubing in the Moody chart.

The aim of this study is to demonstrate how the 12 October 1992 Cairo earthquake relates to the spatial geometry of the northern Egyptian fault systems. A box-counting algorithm was used, in a focused down approach (from regional to local scales) to analyze the fractal dimensions of the existing faults. The results indicate that these faults display fractal geometries that are self-similar over two to three orders of magnitude. It is shown that the northwest-southeast (Northern Red Sea) trending fault system has the lowest fractal dimension value. Coincidentally, this fault trend is the one that the fault plane solution shows to be active.

Gas Well Optimization implementations in the petroleum industry is taking on an important challenge as our industry moves into new frontier production areas such as deep water development and re-invigorated improved recovery operations in producing and abandon reservoirs. Today, high oil and natural gas prices dominate the energy fuels market, forcing companies to look into technologies that will efficiently produce and transport oil and gas to their customers. Attention to pipe performance in the recent past relied on conventional design values such as pipe strength parameters. The introduction of probabilistic evaluation of Oil Country Tubular Goods (OGCT) in the 1990s has provided a more focused approach to tubular strength design. Presently, strength optimization is not the only most cost-effective design concern. Current piping design is more concerned with the ability of pipes to transport fluids at a substantial reduced drag. This resistance to flow is caused mainly by inherent surface roughness due to pipe fabrication and/or corrosion products. A significant outcome in the reduction of surface roughness in pipes can help in optimizing deliverability of the production system. An application of a successful flow assurance program is the result of engineering and scientific knowledge integration, technological know-how, staff proficiency, and operability. Our results are based on impact of surface roughness reduction as a result of utilizing internally coated pipes and newly developed alloys used in OCTG. Our approach to estimate the average surface roughness for modern pipes is based on using our new relative roughness tables and a graph (Farshad et al., 2006) in computer models showed a decrease in the pressure drop with an accompanying increase in the fluid throughput. The presenting case histories using the newly developed surface roughness values for internally coated and newly developed alloyed piping are discussed. Computer models were used to apply the newly developed surface roughness graph and its application to simulate production results for two producing gas wells. Case histories are presented for the two gas wells located offshore Louisiana. TOPS and PIPEPHASE® 7.2 computer models were used to investigate the impact of changing the internal surface roughness of the tubing on production-performance (Simsci, 1999). Modeling results from one of the two Gulf of Mexico gas wells using different well production scenarios showed that gas flow rates increased by 24.5% when substituting a proprietary modified epoxy coated plastic tubing, and a 14.06% increase in flow rates for proprietary liquid phenolic coated production tubing over traditional bare carbon steel pipe. It is apparent that these results justify departure from existing pipe design practices.

Strike-slip faults are prevalent in petroleum reservoir accumulations. Understanding of flow dynamics of sealing and non-sealing strike-slip faults is necessary for offshore producing companies to evaluate the number of wells required to efficiently drain a given hydrocarbon reservoir. A comprehensive pressure transient model characterization study of sealing and partially communicating strike-slip faults was conducted using a commercially available welltest software package. Emphasis was on the use of the log-log pressure derivative (LPD) as the key diagnostic tool, considering that the LPD is, perhaps, the most widely used welltest interpretation technique. The research problem was reduced to running numerous numerical simulations on several strike-slip fault configurations that studied three key variables, such as the magnitude of the strike-slip displacement, the degree of leakiness of the fault and the position of the wellbore relative to the leaky fault. Our results demonstrate that all three key variables affect the resulting LPD and the LPD can be complex, which in the absence of adequate understanding of reservoir geology could lead to misdiagnosis or erroneous reservoir behavior inference. It appears that buildup data interpretation is more severely affected than drawdown data interpretation. Quantitative analysis of the data, assuming no prior knowledge of the presence of a leaky fault, indicate reasonable estimate of formation capacity and total skin factor, but estimate of reservoir boundaries or size can suffer, depending on the level of the three factors considered.

Publisher Summary Abnormally high-pore fluid pressures may result from local and regional tectonics. The movement of the Earth's crustal plates, faulting, folding, and lateral sliding and slipping, squeezing caused by downdropping of fault blocks, diapiric salt, and/or shale movements, earthquakes, etc. can affect formation pore pressures. Due to the movement of sedimentary rocks after lithification, changes can occur in the skeletal rock structure and interstitial fluids. A fault may vertically displace a fluid-bearing layer and either create new conduits for the migration of fluids, giving rise to pressure changes or create up-dip barriers giving rise to isolation of fluids and preservation of the original pressure at the time of tectonic movement. Sahay noted that this barrier may be created by either the fault itself or by bringing the impermeable layer in contact with the permeable layer up-dip. In strongly folded formations, there is a reduction in pore volume (due to compression) along with an attenuation of competent layers (in limbs) and accumulation in the cores of anticlinal folds. An additional rupturing of layers of formations also takes place due to squeezing of and stretching of the skeletal rock structure beyond its elastic limit. Thus, there is a development of high-fluid pressure in isolated blocks.

Publisher Summary Interstitial (intergranular or formation) fluid pressures, either above or below the hydrostatic pressure, occur around the world under a wide range of geological conditions. Any pressure that is either above or below the hydrostatic pressure is referred to as an abnormal formation pressure. Pressures above the hydrostatic pressure are often referred to as abnormally high (AHFP) or surpressures. Pressures below the hydrostatic pressure may be referred to as either abnormally low (ALFP) or subpressures. The object of early formation analysis of abnormally pressured zones was primarily to predict and identify these zones prior to drilling into them. This need for prior knowledge was motivated by the economic losses that were often experienced by suddenly drilling into an unrecognized abnormally pressured region. Attention must be paid to pore fluid and rock stresses in sedimentary sequences, because the knowledge of vertical and lateral stress patterns in a depositional basin is helpful in evaluating its history and development. A thorough quantitative understanding of compaction mechanics, the relationship between the total overburden stress, effective stress, and pore stress (pressure) in fine-grained clastics is required to recognize the potential development of abnormally high-pressured formations.

Publisher Summary Much has been written in the petroleum geology literature on the geochemical evolution of pore liquids and gases associated with fluid flow systems in recent and ancient sedimentary basins. The dialogues include observations about the origin of interstitial fluids, measurements of the active chemical diagenetic processes, and resulting mass-transport properties, which arise during the development of sedimentary basins. Effects of thermal and chemical factors and the dynamic transfer of fluids within the basins leave imprints on the pore–fluid chemistry and generation of abnormally high- (AHFP) or abnormally low-formation pressures (ALFP). This chapter presents and validates a hypothetical model that explains the differences between the salinities of pore water in sandstones and shales in the gravitationally compacted sedimentary basins of Tertiary age. The explanation presented here is based on two diverse, relative scales of resolution—microscopic (10–2 to 10–4 m) and gigascopic (> 105 m). The gigascopic scale presents evidence from field observations, whereas the microscopic scale focuses on laboratory experiments that dealt with the chemistry of fluids in the pore space. Mathematical and conceptual models are presented and discussed, which support these observations. Additionally, the relevance of the isotopic character of shale pore water is evaluated for this environment.

Publisher Summary For the South Caspian basin, the findings of Buryakovsky et al. can be summarized as follows. (1) Regionally developed abnormally high-formation pressures were encountered onshore of Azerbaijan and offshore of the South Caspian basin. (2) Paleogene to Neogene shales and argillaceous rocks, widespread in the geologic section of Azerbaijan and the South Caspian basin, consist of montmorillonite (smectites), hydromica (illite) and mixed-layered minerals. (3) The incomplete compaction of such argillaceous rocks, even at depths down to 6.5 km, is explained by the comparatively young age, a high-sedimentation rate (up to 1 km per one million years), their great thickness, and incomplete squeezingout of pore water. (4) The montmorillonite content of the Baku Archipelago shales is constant down to depths of 6.5 km, because the formation of secondary montmorillonite from hydromicas predominates over the transformation of primary montmorillonite. (5) A formula was proposed for the limiting depth at which montmorillonite can occur for any specific thermobaric conditions and, particularly, when the actual pore pressure differs from the normal hydrostatic one. (6) The sealing properties of argillaceous rocks at depths greater than 6.5 km probably persist, because of the presence of large amounts of montmorillonite. If accompanied by (1) good reservoir rock properties, (2) abnormally high pore pressures in shales and sandstones, and (3) relatively low-formation temperatures (which allow hydrocarbons to persist), the writers suggest that the South Caspian basin may contain commercial oil and gas accumulations at depths of 9 km, and deeper. (7) Development of abnormally high pore pressures may lead to lateral rock-density variation and, under certain geologic conditions, to folding, clay diapirism, mud volcanism, and earthquakes.

Many petroleum engineering programs have instituted industry advisory boards during the last decade. These boards are designed to assist the petroleum engineering program in meeting the needs of petroleum engineering education and industry. This is accomplished by providing the programs with access to industry resources of manpower, capital, equipment and facilities. Properly used these resources can be leveraged far beyond those readily available to an individual program. An active board, with a committed faculty, can help develop a respected and successful education program within the petroleum community This paper presents a general overview of advisory boards and how they can be utilized in an effective manner.

Publisher Summary This chapter describes stresses in sediments. Subsidence in human development results in environmental concerns that may not be amenable to control or abatement, such as the breaking of a dam or subsidence within a city. Land subsidence is the result of tectonic motions, subsurface grain compaction caused by overburden loading, and withdrawal of fluids. Cemented sand reservoirs may undergo significant compaction if the reservoir has great thickness and large areal extent. Significant compaction with subsequent subsidence may take place in productive zones containing interbedded clay and shale even if the productive formation has low compressibility. Physical changes occurring in the sediments during the subsidence of a depositional basin are directly related to the evolution of stresses within the basin. Information on the thickness of sediments, facies changes, fluid-displacement phenomena, distribution of unconformities, structural geometry, stress–strain relations, and location of abnormally high fluid pressure zones is needed for a satisfactory analysis of subsidence. A simple hydrogeological cycle starts with tectonic depression and transgression, followed by a period of subsequent uplift and regression and terminates prior to the initiation of a new depression and regression.

Publisher Summary This chapter discusses the fundamental relationships for the porous medium of carbonate rocks, both from a pore-size portrait scale and at a macroscopic descriptive scale. There is a reasonable correlation between the porosity and permeability of cores having irreducible (immobile) fluid saturation in the minute pores, crevices, and so on, which do not have a major effect on the flow of fluids through the rock. Several correlations are developed that relate specific surface area of hydrocarbon-bearing reservoir rocks to other petrophysical properties (such as porosity, permeability, and pore size) and residual water saturation. Permeability is one of the most important parameters describing a porous medium, its measurement normally requires a rock sample that is of a suitable size (e.g., 5 cm x 5 cm x 5 cm) and has a simple geometric shape (for example, a cylinder or a cube). Correlations between the permeability and other easier-to-measure quantities, therefore, are discussed extensively both experimentally and theoretically. Several theoretical relationships between tortuosity and porosity have been developed for simplified models, two of which are presented.

Publisher Summary This chapter discusses several different compressibility––bulk compressibility, pore compressibility, formation compressibility, rock solids compressibility, and pseudo-bulk compressibility––depending on the method of its determination. The best method of obtaining accurate compressibility data is to test core samples in both hydrostatic and uniaxial compaction apparatuses. These tests should be performed at temperatures and pressures existing in the reservoir. Before using available compressibility data, however, one should consult the following checklist: the formula used in the calculations, loading condition exists in the reservoir, and the tested samples dried or did they contain interstitial fluids. Compressibility data is presented on consolidated rocks and unconsolidated sediments, as well as on shales and various clay minerals. A correlation between effective rock compressibility c f and porosity is presented. A comparison of the relationship between compressibility and applied pressure for unconsolidated sands, illite clay, limestone, sandstones, and shale is presented. Pore volume compressibility as a function of porosity for consolidated, friable, and unconsolidated reservoirs under hydrostatic loading conditions.

During the past quarter of a century, the exploitation of oil and gas reserves, associated with thick sequences of very fine-grained and coarsegrained rocks in the Tertiary Basins, have become increasingly important for fulfilling the world's energy needs. Many exploration and reservoir development problems have arisen which demand an analytical solution. The solution of many scientific and technological problems associated with these geologically young basin sediments requires knowledge of the origin, maintenance, and distribution of abnormally high pore-fluid pressures, chemical changes induced in the interstitial water by compaction, origin and migration of hydrocarbons, temperature gradients, clay minerals phase changes, and subsidence of the surface. Successful drilling to depths greater than 20,000 ft in these sediments and the amounts of hydrocarbons discovered and produced depend to a great extent on our knowledge of the physical and mechanical properties and deformation characteristics o...

A new computational method is presented which calculates geothermal heat flow values and geothermal gradients with more precision than permitted by previously published techniques. The data required are: geothermal temperature at a known depth, mean surface temperature, the rock types in the stratigraphic column and the thermal resistivity values for the different types of rocks. This method is valuable in areas that have no measured gradient values. Basic equation used was the Fourier heat transfer equation Q/A = −1/ρi (∂T/∂x) where Q/A is heat flux in μcal/(cm2 s), ρi is thermal resistivity (°C s cm/μcal) and ∂T/∂x is the x component of the temperature gradient (°C/cm). The thermal resistivity was allowed to vary linearly with temperature ρi = ρio [1 + Ki (T − 30)] where ρi is thermal resistivity of the lithographic segment «ia at a temperature T, ρio is thermal resistivity at 30°C and Ki is the temperature coefficient of thermal resistivity. The procedure consisted of integrating the combined equation for heat flux in terms of temperature dependent resistivity. Two iterative solutions were used to simplify the calculations: exact and approximate. The heat flux for each well was assumed to be 1.0 HFU and segmental temperatures were calculated from the bottom (arbitrarily) up, until a surface temperature was obtained. The calculated surface temperature could then be compared with the mean surface temperature (MST). Correction in the heat flux value was made until the calculated surface temperature and MST agreed. An analysis of three deep Appalachian test wells was made and the results showed the critical importance of lithographic ordering and the temperature dependence of thermal resistivity upon calculated geothermal quantities.

Gamma ray spectral logging devices, in addition to total gamma ray counts, record the individual contributions of potassium-40 isotope, uranium series nuclide bismuth-214, and thorium series nuclide thallium-208. Application of these data to identify fractured shale reservoirs and source-rock characteristics of argillaceous sediments is discussed. Introduction Highly radioactive, black, organic-rich, and gaseous shales are encountered in several U.S. geologic provinces. Such organic-rich shales are not only potential source rocks but frequently owe their localized but significant production potential to natural fracture systems in an otherwise impermeable rock. These natural fracture systems normally are concentrated in the interbedded brittle, calcareous, cherty, or silty zones.Conventional logging and interpretive techniques are not adequate to evaluate satisfactorily the complex and frequently fractured shale reservoirs. Novel applications of gamma ray spectral logging data for characterizing these shale formations as to their reservoir properties and source-rock potential (SRP) are discussed here.Calcareous and silty zones, both characterized by low values of potassium and thorium but excessively high values of uranium, are located easily with natural gamma ray spectral information obtained from highly sensitive scintillation spectrometer logging tools. These interpretive concepts already have assisted in many successful gas- and oilwell completion and recompletion attempts in the more permeable and/or fractured intervals of such shale formations.Such logging information also allows a continuous monitoring of the SRP of shales in open and cased boreholes. Hence, both vertical and lateral SRP variations can be studied using appropriate mapping techniques. Gamma ray spectral data also assist in detailed stratigraphic correlations, because in addition to total gamma ray counts, individual gamma rays emitted by potassium-40 (K(40)), the uranium series nuclide bismuth-214 (Bi(214)), and the thorium series nuclide thallium-208 (TI(208)) are measured.K(40) emits gamma rays at 1.46 MeV, Bi(214) emanates gamma rays at 1.764 MeV, and TI(208) emanates gamma rays at 2.614 MeV. These nuclides are of particular interest to the oil industry because all are found, in various amounts, in subsurface formations as constituents of potential reservoir rocks. Based on an extensive literature search and on recent field observations, a data compilation has been published to document potassium, uranium, and thorium distributions in various rock types.This discussion focuses on the use of gamma ray spectral logging to interpret the reservoir pore structure present in shales. JPT P. 2053＾

Summary This paper discusses test activities and results from four selected wells used to acquire coalbed methane data in the Illinois, Piceance, Arkoma, and Green River basins. Techniques used to evaluate the coalbed gas resource are well logging, conventional and sidewall coring, gas desorption of the coal cores, and drillstem testing. Experience gained by employing these techniques is presented. Introduction Methane recovery from coal beds is one of several unconventional gas resources currently under evaluation by the U.S. DOE and industry. The methane gas associated with both minable and unminable coal seams represents a sizable resource. Approximately 700 to 800 Tcf of gas is locked in these beds, of which an estimated 300 Tcf is believed to be contained in minable bituminous coal beds. No universally accepted estimate exists for the recoverable portion.An integral feature of the joint Methane Recovery From Coalbeds Project (MRCP) of DOE's Morgantown Energy Technology Center (METC) and industry is to construct a data base which will provide essential information on quantity and quality of coalbed methane, its distribution, and production characteristics. This can be accomplished by evaluating each coal bed encountered in the candidate wells using conventional reservoir assessment methods.Methane, the major component of natural gas, is generated during geologic formation of coal and frequently is trapped in the coal and associated strata. As might be expected, the distribution of existing coal resource data is influenced more by local economics than by the actual concentration of total coal deposits. The most accessible deposits have been mapped and defined in preference to the deeper, less economical minable and unminable coal seams. Fig. 1 outlines the bituminous and subbituminous coal fields located in the conterminous U.S. TRW Inc.'s Energy Systems Group, as integrating contractor for the MRCP, has prepared plans in conjunction with METC to examine 380,000 sq miles of coal-bearing rocks estimated to contain 700 Tcf of methane. The distribution of the gas content in the coals to be tested is unknown. The initial evaluation efforts have concentrated on 80,000 sq miles of this area where the probabilities of finding, producing, and using the methane are high. A cooperative drilling, coring, logging, and well testing program was initiated to extend the existing data base.The basins selected for immediate testing are listed in Table 1. The selections were guided by these criteria:physical and chemical characteristics of coali.e., fixed carbon, percent volatiles, percent sulfur, etc. (higher-rank coals generally contain more methane),bed depth: east greater than/equal to 1400 ft, west greater than/equal to 700 to 800 ft (deeper coals are more likely to have retained the methane),total effective coal thickness: east greater than/equal to 20 ft for high rank, west greater than/equal to 30 ft (higher total production per well possible on basis of multibed completion),individual seam thickness: minimum of 5 to 10 ft for shallow beds, with multiple coal beds considered as one if separated by permeable rock units (minimize need for multiple fracturing), andareal extent: continguous basin (allow extrapolation of results to a wider area). Based upon the criteria, portions of major basins were selected as the targets for initial resource delineation activities. A total of 80 wells will be evaluated for coalbed methane content; 32 wells have been drilled and tested as of Aug. 1, 1980. JPT P. 195^

Summary Two primary objectives of TRW's involvement as integrating contractor for the U.S. DOE's Methane Recovery from Coalbeds Project (MRCP) are (1) to demonstrate that this unconventional methane resource can be characterized and (2) to select target sites with the greatest production potential. It was contemplated that the wireline carbon/oxygen (C/O) logging tool could help the project's activities meet these objectives. A study using the C/O tool was initiated in the Arkoma basin at the Barringer Well 1–11 located in the Kiowa syncline, Pittsburg County, OK. Several nearby wells are producing methane commercially from strata that are associated with these coalbeds. The C/O log has shown that the various coalbeds in the Barringer well can be delineated. C/O ratio measurements have proved a valuable means of determining the presence of coal behind casing. Results from the Barringer well study indicate that this tool can identify and locate coal behind casing for possible recompletion and production of associated coalbed methane. Comparative data based on previous logging programs for the uncased Barringer Well 1–11 and laboratory studies on the coal are presented. Introduction The Arkoma basin contains extensive bituminous coal reserves. Accurate coalbed correlation and coalbed thickness are essential prerequisites to the determination of coal resources and reserves, especially those beds that are particularly gassy. The coals in the basin are generally considered moderately to highly gassy (appx. 200 to greater than 500 cu ft/ton). A range in coalbed methane contents is to be established for each bed and is used in conjunction with the verified coalbed reserves to provide an estimate of the volume of methane in place. Mustang Production Co. of Oklahoma City completed a successful coalbed characterization field test using the C/O tool during Jan. 1980. The cased test well. Barringer 1–11, is located in the Kiowa syncline (west central part of the Arkoma basin), Pittsburg County, OK (Fig. 1). This well penetrates about 18 possible coalbeds of Desmoinesian age (Pennsylvanian) over a 4.635-ft interval (Table 1). Several offset wells are producing methane commercially from strata associated with coalbeds in the Kiowa syncline. The objectives of this field test were to demonstrate that coalbeds can be (1) identified and located behind casing, (2) distinguished from gas-producing zones. and (3) shown to contain gas. Examples of the C/O tool response to coal are presented. Discussion of the field test includes a description of completed MRCP activities in the Arkoma basin, the resulting MRCP well test data, the C/O log field test configuration, and the test description. Comparison of the C/O results were made with openhole log information. Results have shown that the C/O logging tool successfully delineated the various coalbeds in the Barringer well. Application of the C/O log includes:identification of coalbeds behind casing,differentiation of coalbeds from gas zones,location of thin coalbeds on the order of 1 ft thick, anddetermination of coal quality. C/O Tool Response to Coal The C/O log utilizes a high-energy pulsed neutron source that produces 14-MeV neutrons by the deuterium/tritium reaction. Under high-energy neutron irradiation, elements emit gamma rays with specific energy levels. JPT P. 421^

Fourteen soil samples from Menlo Park, California (mainly rock flour) and Conejo Valley, near Ventura, California (illitic soil) were treated electrochemically in the laboratory. The equipment and procedure used in the laboratory are described. Electrolyte solutions of calcium chloride, aluminum sulfate, aluminum acetate and aluminum silicate were used in the experiments. X-ray diffractograms were prepared of samples from Menlo Park, before and after treatment, in order to detect any change in soil mineralogy due to electrochemical treatment. The results showed that shrinkage of soils rich in clay minerals may be reduced considerably upon treatment; but, for rock flour (quartz, feldspar, etc. of clay size) the improvement may be insignificant.

The total mineralization of solutions squeezed out of montmorillonite clay saturated in sea water was determined at different overburden pressures. The subsequent fractions of expelled solutions were also analysed for various anions (Cl−, SO2-4, HCO−3, F−) and cations (Na+, K+, Mg2+, Ca2+, B3+). The results indicate that the concentrations of squeezed-out solutions during the initial stages of compaction (at pressures up to 35 kg/cm2) are slightly higher than that of interstitial solution present initially. The concentration of squeezed-out solution goes through a maximum, or at least remains constant, before starting to decrease with increasing overburden pressure.

SUMMARY The possibility of using viscosities of clay plus water systems for determining the mineralogic type of clays was investigated by the writers.

A brief review of some of the processes which affect the chemical composition of interstitial waters is presented. The experimental results obtained by the writers indicate that the mineralization of squeezed-out solutions progressively decreases with increasing overburden pressure. Possibly, as the underground waters move through a thick shale sequence, the mineralization could increase to levels found in oil-field brines; the Ca/Cl and Ca/Na ratios could, but not necessarily, also increase.

The tensile strengths of a variety of granitic rocks from California were found to be inversely proportional to quartz content. This relationship is attributed to textural differences as suggested by high-quartz rocks composed of equidimensional grains showing little crystal intergrowth, or interlocking, whereas low-quartz rocks consist of interlocking laths and prisms.

Abstract During the past quarter century, the exploitation of oil and gas reserves, associated with thick sequences of very fine-grained and coarse-grained rocks in Tertiary basins, have become increasingly important for fulfilling the world's energy needs. Many exploration and reservoir development problems have arisen which demand an analytical solution. The scientific problems have arisen which demand an analytical solution. The scientific and technological problems associated with these geologically young basin sediments include the origin, maintenance and distribution of abnormally high pore-fluid pressures, chemical changes induced in the interstitial water by compaction, origin and migration of hydrocarbons, temperature gradients, clay minerals phase changes and subsidence of the surface. Successful drilling to depths greater than 20,000 feet in these sediments and the amounts of the hydrocarbons discovered and produced depend to a great extent on our knowledge of the physical and mechanical properties and deformation characteristics of the sediments and the interrelationships between their various petrophysical and fluid properties. This paper is an historical review of studies dealing with the effects that gravitational compaction of sediments has on hydrocarbon reservoirs and source beds. Specific attention will be given to the generation of abnormal pore-fluid pressures, chemistry of interstitial fluids, compaction models, pressures, chemistry of interstitial fluids, compaction models, compressibility of the reservoir rocks and surface subsidence. Introduction It has been postulated that gravitational compaction of sediments is directly related to the following parameters and can be functionally represented in the following manner: C = (1) Where C is the degree of compaction, is the stress on the sediment system, is the velocity parameter for solids and interstitial fluids in the system, is the density, is the bulk volume of the sediments, is the porosity, is the permeability of the system, is the burial depth, t is the time, T is the geothermal temperature, and c represents the compressibility relationships. Gravitational compaction of sediments under the influence of their own weight has long been a recognized geologic phenomenon. In the seventeenth century Steno attributed variations in the attitude of sedimentary formations to compaction.