High Shale Content Research Articles

Petrophysical Evaluation of Arkoses Reservoirs Based on Well Logs and Plug Samples: A Case Study From Alagamar Formation, Southeastern Portion of Onshore Potiguar Basin, Brazil

The Potiguar Basin is a sedimentary basin located in northeastern Brazil. It covers about 48,000 km² and extends from onshore to offshore. The onshore basin is thought to have formed during the Late Cretaceous, as a result of the opening of the Equatorial South Atlantic Ocean, filled with a thick sequence of sedimentary rocks, including sandstones, shales, and limestones, which were deposited in a variety of processes, including marine, deltaic, and fluvial. The study area is in the southern portion of the basin and the reservoir is composed of arkose sandstones deposited by alluvial fan and fluvial systems of the Upanema Member of the Alagamar Formation, which belongs to the post-rift phase of the Potiguar Basin. Recently, new drilling campaigns revealed a reservoir heterogeneity in these deposits, which requested a new petrophysical approach. Using conventional well logs and petrophysical laboratory analysis of plug samples, this study evaluated the best way to calculate the effective porosity, and shale volume and to understand the stratigraphic controls in the distribution of these properties. Three reservoir zones were mapped: the basal one, Zone 3, has disconnected sand bodies, low porosity, and high shale content; Zone 2 has better petrophysical properties, lateral distribution, and connectivity between the fans and Zone 1 is the better reservoir zone with larger sand bodies, higher porosity values, and well-connected fans.

Numerical simulation of resistivity and saturation estimation of pore-type gas hydrate reservoirs in the permafrost region of the Qilian Mountains

Abstract The pore-type hydrate reservoirs in the permafrost region of the Qilian Mountains (PRQM) have complex characteristics, including low porosity, low permeability, high shale content, and conductive minerals. Currently, the research on the electrical properties of these reservoirs still needs to be sufficiently in depth, and there are limitations in well-logging evaluation methods. To fill in this gap, a conductivity model of pore-type gas hydrate reservoirs (GHRs) is established based on the pore-combination modeling theory to investigate the influencing factors of the resistivity characteristics of GHRs through numerical simulations. The comparison between the laboratory-measured resistivity of different hydrate saturations and the results of the calculated model shows good agreement, indicating the accuracy of the conductivity model in describing the electrical characteristics of GHRs in the PRQM. Compared to conductive minerals, the numerical simulation results indicate that the high shale content is the main reason for the decrease in resistivity of pore-type GHRs in the study area. The hydrate saturation evaluation of well DK-3 from 386.3 to 393.6 m depth shows that the hydrate saturation ranges from 5.1 to 66.4%, with an average value of 44.0%. The identified hydrate interval using this model is consistent with the actual hydrate interval encountered during the drilling. This study, as an innovation, can help clarify the conductive mechanism of pore-type GHRs in the PRQM and provide more accurate parameters for evaluating gas hydrate resources in the study area.

Petrophysical properties identification and estimation of the Wufeng-Longmaxi shale gas reservoirs: a case study from South-West China

Abstract Petrophysical properties are critical for shale gas reservoir characterization and simulation. The Wufeng-Longmaxi shale, in the south-eastern margin of the Sichuan Basin, is identified as a complex reservoir due to its variability in lithification and geological mechanisms. Thus, determining its characteristics is challenging. Based on wireline logs and pressure data analysis, a shale reservoir was identified, and petrophysical properties were described to obtain parameters to build a reservoir simulation model. The properties include shale volume, sand porosity, net reservoir thickness, total and effective porosities, and water saturation. Total and effective porosities were calculated using density method. Shale volume was estimated by applying the Clavier equation to gamma-ray responses. Sand porosity and net reservoir thickness were evaluated using the Thomas–Stieber model, and the Simandoux equation was used to compute water saturation. The results indicate that the reservoir is characterized by a relatively low porosity and high shale content, with shale unequally distributed in its laminated form (approximately 75%), dispersed (about 20%), and structural form (5%). This research workflow can efficiently evaluate shale reservoir parameters and provide a reliable approach for future reservoir development and fracture identification.

Study on Green Nanofluid Profile Control and Displacement of Oil in a Low Permeability Reservoir.

Low permeability reservoirs are characterized by low permeability, small pore throat, strong heterogeneity, and poor injection-production ability. High shale content of the reservoir, strong pressure sensitivity, micropore undersaturation, and significant water-lock effect in water injection development lead to increased fluid seepage resistance. There is an urgent need to adopt physical and chemical methods to supplement energy and improve infiltration efficiency, thereby forming effective methods for increasing the production and efficiency. Aiming at the characteristics of ultralow permeability reservoirs, in this paper, a green and environmental friendly biobased profile control and displacement agent (Bio Nano30) has been developed using noncovalent supramolecular interaction. Physical simulation experiments illustrate the profile control and displacement mechanism of Bio-Nano30. Laboratory experiments and field applications show that good results have been achieved in oil well plugging removal, water well pressure reduction and injection increase, and well group profile control and oil displacement. This research has good application prospects in low permeability heterogeneous reservoirs.

2D and 3D visualization of aquifer sediments, surface water seepage and groundwater flow using DC-resistivity, DC-IP, and SP methods, West El-Minia, Egypt

In this study, the SP, DC-Resistivity and DC-TDIP methods were used and included 21 sites for determining the groundwater conditions and visualizing the aquifer sediments, surface water seepage, and groundwater flow in 2D and 3D. The results indicated the occurrence of Quaternary and Tertiary deposits, as well as shallow aquifer of Eocene fractured limestone and Quaternary deposits. The resistivity, chargeability and SP values were compared with each other and 2D and 3D visualization models were designed for these values to understand the sediment distribution and its geological and hydrogeological implications. High to medium, low and very low chargeability values indicated the compact sediments with high shale content, water-bearing layers and freshwater zones and dry sediments, respectively, and varied with the water amount, salinity and effective porosity. Low to very low values of SP indicated the occurrence and high accumulation of groundwater and an increase in shale, permeability and groundwater flow and source, and possibly salinity. The results showed that the resistivity, chargeability and SP values had an important role in separating the dry and saturated sediments and defining the fault zone, determining the source of surface water seepage, classifying the depths of high, medium and low groundwater accumulation and flow and permeability. The IP depended highly on the water amount and shale content and it was interesting in groundwater exploration with resistivity and in differentiating between groundwater and clays. The SP assisted in delineating the surface water seepage and groundwater source and flow direction, and predicting the sediments permeability.

Modified smart water flooding for promoting carbon dioxide utilization in shale enriched heterogeneous sandstone under surface conditions for oil recovery and storage prospects.

Modern oil reservoirs exhibit high macro-scale heterogeneity, i.e., presence of shales and clays, which complicate the implementation of conventional enhanced oil recovery (EOR) practices. Hence, there is a need to investigate new class of EOR methods which not only improve recovery of oil from reservoir but also reduce formation damage. Thus, in this study, synthetic smart brines of varying salinity were formulated to investigate carbon utilization in shaly-sandstone for oil recovery and sequestration applications. To prepare shaly-sandstone samples, shale content in sand varied between 0 and 25 wt%. The addition of shale reduced porosity and permeability of sand-packs, and porosity ~ 25 and permeability < 10 md were measured for a combination of 75% sand + 25% shale which were originally 38% and 692 md for 100% sand + 0% shale. The oil recovery experiments were performed at temperature ≈ 40°C and ambient pressure. The impact of shale content was insignificant on CO2-based oil recovery resulting its value remained nearly constant (5-7%). Smart saline water (SSW) solutions were prepared through the dilution of formation water (FW) of typical oilfield salinity and used these SSW solutions in investigating shale swelling and interfacial tension with CO2. Compared to other SSW solutions, SSW-2 (1 part FW/9 part water: 1/10th of FW) demonstrated superior control on mitigating shale swelling (by 67%) and reduce interfacial tension (by 30%) when compared to FW. Moreover, it helped to mobilize higher amount of oil (50% OOIP) from sand-pack (80% sand + 20% shale) in which conventional water flood failed to perform, indicating its viability for EOR from heterogeneous reservoir. In addition, SSW solutions promoted use of carbonated (CO2-enriched) water injection for oil recovery from sandstone exhibiting high shale content of 20% as over 5-8% higher oil recovery was obtained compared to conventional water flooding. Comparative performance of water flooding, salinity water-alternating CO2 flooding and carbonated smart water injection in heterogeneous sandstone.

Spatiotemporal variations in seismic attenuation during hydraulic fracturing: A case study in a tight oil reservoir in the Ordos Basin, China

During hydraulic fracturing (HF) stimulation for unconventional reservoir development, seismic attenuation has a significant influence on high-frequency microseismic data. Attenuation also provides important information for characterizing reservoir structure and changes to it due to HF injections. However, the attenuation effect is typically not considered in microseismic analysis. We have adopted the spectral ratio and centroid-frequency shift methods to estimate the subsurface attenuation (the factor [Formula: see text]) in a tight oil reservoir in the Ordos Basin, China. The P- and S-wave attenuations are calculated using the 3C waveform data recorded by a single-well downhole geophone array during a 12-stage HF stimulation. Both methods provide similar results (with differences in [Formula: see text] of absolute values less than 0.010 for P- and S-waves). For individual events, their median [Formula: see text] values calculated from different geophones are selected to represent the average attenuation. Spatiotemporal variations in attenuation are obtained by investigating [Formula: see text] values along propagating rays linking different source–receiver pairs. The [Formula: see text] values derived at different HF stages reveal significant attenuation in the targeted tight sandstone layer (0.030–0.062 for [Formula: see text] and 0.026−0.058 for [Formula: see text]), and the attenuation is apparently increased by fluid injection activities. We explain the sudden decrease in attenuation near the geophone array as a result of high shale content using log data from a horizontal treatment well. The consistency between the [Formula: see text] values and horizontal well-log data, as well as the HF process, indicates the reliability and robustness of the attenuation results. By studying spatiotemporal variations in attenuation, the changes in subsurface structures may be quantitatively characterized, thereby creating a reliable basis for microseismic modeling and data processing and providing additional information on monitoring the HF process.

Technologies for Snubbing Services in Horizontal Shale Oil Wells in the Cangdong Sag

The shale oil reservoir in the Kong-2 member of the Cangdong Sag has ultra-low porosity, ultra-low permeability and high shale content, and thus, it is prone to be contaminated by invasion of fluids including killing fluid during operations. Regarding this problem, the sucker rod pumps, the lift technology of electric submersible pumps, and the associated production string and downhole tools commonly used in shale oil wells were optimized. Then, the technologies for snubbing services in the horizontal shale oil wells in the Cangdong Sag were formed with snubbing service with prefabricated inner blowout preventers, completion with controllable bridge plugs that can temporarily close wellbore, and under-pressure pumping-down operation with cable-laying coiled tubing. Field applications showed that this technologies could successfully address the problems such as lined tubing sealing failures of sucker rod pumps and under-pressure operation failures of electric submersible pumps,etc. After the operations, the reservoir was not contaminated and the pumping-down operation were free from waiting for complete pressure relief.

Deep learning and comparative study of gas saturation models for tight sandstone reservoirs with strong heterogeneity: a case study of the Upper Triassic Xujiahe Formation in Sichuan Basin, China

Advanced and effective models for gas saturation interpretation in tight reservoirs are mainly based on electricity and acoustics; however, these methods are not always effective, especially in determining the rationality of some undetermined constant methods. Therefore, the purpose of this study is to achieve high-precision prediction of gas saturation in tight reservoirs by comparing the principles and case analysis results of different typical gas saturation models. In this paper, the Archie formula, the three-phase Biot-type equation, and the effective medium symmetrical conduction model were used to evaluate the gas saturation of tight sandstone reservoirs from the perspective of electricity and acoustics. Through the research of this paper, we determined the Archie constant of the target layer. In the application of the three-phase Biot-type equation, an adaptive method is proposed to obtain the value of the formation consolidation parameter α. In addition, a quantitative relationship between resistivity and α was established. The evaluation accuracy of this method is less affected by the shale content, although it will be affected by the true Sg of the formation. The effective medium symmetrical conductivity model has a good predictive ability for Sg in sandstone reservoirs with high shale content. The research results can provide a wide range of references for the quality evaluation of tight sandstone reservoirs.

Permian Basin: Use of In-Situ Mechanical Rock Properties Improves Completions

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 191406, “Using In-Situ Mechanical Rock Properties To Target Landing Zones and Improve Completions in the Permian Basin,” by E.L. Scott, A.M. Hildick, and C. Glaser, Fracture ID, and E. Petre, Hunt Oil, prepared for the 2018 SPE International Hydraulic Fracturing Technology Conference and Exhibition, Muscat, Oman, 16–18 October. The paper has not been peer reviewed. Optimizing horizontal well placement is not limited to identifying the most-favorable reservoir, but also involves identifying the ideal target window within that reservoir. Gathering drill-bit geomechanics data provides a lower-cost and lower-risk method to acquire mechanical rock properties in long horizontal wellbores. By integrating data sets with mechanical rock properties recorded while drilling, operators can have significantly higher confidence in choosing a target landing zone and improving completions. The complete paper presents two detailed case studies from the Permian Basin. Introduction In this paper, the authors combine the characterization of petrophysical and geomechanical properties into what they call a petromechanical work flow. Typically, petrophysical and geomechanical properties are characterized using data acquired by wireline logs. In vertical wells, wireline logs represent, traditionally, the least-intrusive manner of acquiring high-resolution data. With additional cost and rig time, cores of the formation rock can be exhumed to analyze its properties on surface. In horizontal wells, both wireline logs and conventional cores are costly and operationally challenging. Because of the economic and operational burden, operators typically avoid collecting geomechanical data in horizontal wells. Besides these traditional measurements, the novel technique of using drill-bit geomechanics can enable measurement of geomechanical properties while drilling. Compared with wireline logs and core analysis, this technique is less costly and has a lower risk in long horizontal wells. Drill-Bit Geomechanics Drill-bit geomechanics provides mechanical properties through continuous, high-resolution measurements of drilling-induced vibrations. Triaxial accelerometers, which sample at 1 kHz, record the vibrations while positioned directly behind the drill bit. Earthquake seismology models allow a transformation of the high-frequency, triaxial, drilling-induced vibrations into mechanical rock•properties. The drill-bit geomechanics method determines mechanical properties by using stress-strain relationships and isotropic stiffness coefficients. Additionally, the method describes anisotropy by solving for transversely isotropic (TI) interpretations of the rock matrix. Typically, a vertically transverse isotropic (VTI) matrix contains high shale content or other laminar bedding, while a horizontally transverse isotropic (HTI) matrix contains vertical bedding or fractures. In this paper, the authors define VTI anisotropy as bedding and HTI anisotropy as fracture intensity.

Experimental Study of the Feasibility of Air Flooding in an Ultra-Low Permeability Reservoir

The development effect of water flooding in an ultra-low permeability reservoir is poor due to its poor physical properties and high shale content, so an experimental study of air flooding which helps to complement energy production was carried out. Based on the Accelerating Rate Calorimeter experimental results, the crude oil of N block in L oilfield can undergo low-temperature oxidation reactions, which are the basic condition for air flooding. Three groups of experimental natural cylinder cores designed for oil displacement, water flooding and air flooding were used respectively, and the relationship between differential pressure, oil recovery, injection capacity with injection volume was investigated. It is observed that the recovery efficiency increased 2.58%, the injection-production pressure difference dropped 60% and the injection capability increased 60% in the experiment of shifting air flooding after water flooding to 75% moisture content, compared with water flooding alone. It has been shown in the results that the recovery efficiency improved sharply more than water flooding, the effect of depressurization and augmented injection was obvious, and the air displacement was thus validated. We suggest that other science and technology workers should perform further tests and verify this result through numerical simulation.

Sequence Stratigraphic Analysis from Well Logs of an X-Field, Niger Delta, Nigeria

The sequence stratigraphic analysis of the area was studied using well log information in order to determine the lithostratigraphy, chronostratigraphy, possible reservoir sands, age and depositional environment of the study area for opportunities that will support exploration program. The depositional environment penetrated by the wells interpreted from log signatures gave three major facies association. The blocky and coarsening upward (funnel shape), the blocky and fining upward (bell shape) and the erratic (serrated or spiky) facies representing distributary mouth bar, distributary channel and marine mud facies respectively. The sediment deposition of the coastal deltaic and shallow marine delineated for the wells were inferred from the study. Lowstand Systems Tract (LST), Transgressive Systems Tract (TST) and Highstand Systems Tract are the depositional sequences observed. The Maximum Flooding surfaces observed from the stratigraphy analysis indicate major shale break (high shale content). The study area is dominated by altenation of sand and mudstone lithologies, which occurs in approximate ratio of 60:40. The stratigraphic column of the wells was subdivided into sequence boundary, system tracts and sedimentary cycles based on the integration of the various dataset. Some of the sequences have potential of a source rock and seals. The system tracts have the characteristics of good seal and traps. The Maximum Flooding Surfaces and sequence boundaries observed in the wells are four and five respectively. The depths at which the Maximum Flooding Surface occur are 1300, 9300, 9750 and 7050 ft while the sequence boundaries occurred at the depths of 12150, 10850, 8550, 7425 and 6875 ft respectively.

Magnetic susceptibility and its relation with fractures and petrophysical parameters in the tight sand oil reservoir of Hamra quartzites, southwest of the Hassi Messaoud oil field, Algeria

Abstract Magnetic susceptibility (Ms) measurements were carried out in the cores of six wells distributed throughout the study area of tight sand oil of the Hamra quartzites reservoir, southwest of the Hassi Messaoud oil field. With steps of 2 cm, 8760 Ms values were taken from a total core length of 174 m. In most of the intervals, the contrasts in Ms coincide with high fracture density and high shale content (increase of gamma ray in this interval). The analysis of the hysteresis loops, isothermal remanent magnetizations to saturation (IRMs) and thermomagnetic curves for samples taken from some high interval of Ms shows that magnetite and pyrrhotite are the main magnetic minerals. It demonstrates that fractures can be considered as precipitation environments of the magnetic minerals in the reservoir, which is a good indicator for mineralized fractures. The application of principal component analysis (PCA) to the entire reservoir shows low linear correlation between Ms and the main petrophysical parameters (gamma ray, neutron porosity, density, and saturation of oil). Meanwhile, the application of fuzzy ranking and artificial neural network (ANN) evidenced non-linear relations between these parameters. It is justified by the prediction of the Ms from the petrophysical parameters with an acceptable degree of accuracy. The results obtained using an ANN structure of 25 neurons in a hidden layer show the performance in the test stage with mean square error (MSE), mean relative error (MRE) and correlation coefficient (R) equal to 0.0142, 0.0743 and 0.907, respectively.

Displacement loss on growth faults due to sediment compaction

Compaction models of normal growth faults, combined with displacement data from a natural growth fault (Cape Egmont Fault, New Zealand), are used to quantify the loss of displacement arising from compaction, in circumstances where growth faults are blanketed and buried by compacting sediment in both footwall and hangingwall. Comparison of imposed tectonic displacements with the preserved displacements indicates that although the thicknesses of sand/shale sequences may decrease by up to c. 55% due to compaction, associated losses in displacement on growth faults are typically <20% because they displace partially compacted sediments. The importance of displacement loss generally increases with increases in the depth range over which fault displacements migrate along the compaction curves and in the percentage shale of the faulted sequence. Displacement loss due to compaction is relatively small (<c. 15%) for sand or mixed sand-shale sequences with growth indices greater than c. 0.1 (equivalent to the ratio of the fault throw rate and footwall sedimentation rate), and in these strata decompaction is not required to decipher first-order displacements and fault-growth histories. Decompaction of displacements is of most benefit in circumstances where growth sequences have a high shale content (>70%) and post-faulting burial is large (i.e. km-scale).

ノルウェー領北部北海Ｖｉｇｄｉｓ油田 落差の小さな断層によるシーリングについて

The Vigdis field is located approximately 200km north-west of Bergen in Norway. The water depth ranges from 230m in the south to 300m in the north.The hydrocarbon is accumulated in a westerly tilted fault block in the Tampen Spur area, where numerous fields also have been discovered.The main reservoir rock in the field is the Middle Jurassic Brent Group deltaic sandstone. The Brent delta prograded from south to north with its thickness of around 200m in the field. The Brent Group is traditionally subdivided into five formations in this area from the youngest to oldest: Broom, Rannoch, Etive, Ness and Tarbert. Although each formation basically has a high sand/shale ratio, the lowest sand/shale ratio or relatively high shale content is observed in the Ness Formation which behave very important role in the fault seal in this field.The field, consisting of three structural elements, called Vigdis West, Vigdis Middle and Vigdis East is bounded to the east by a truncation of the Base Cretaceous Unconformity, to the north and west by OWC and bounded to the south by the E-W trending cross fault. The displacement of E-W trending cross faults is so small that the Brent Group is juxtaposed each other across the faults. Thus the faults might be considered to be non-sealing, which was a main exploration risk for Vigdis Middle.After drilling of exploration/delineation wells, the fault plane analysis along each boundary fault revealed that the Ness Formation, richest in shale content enhanced the sealing capacity of fault. The OWC in the field vary among the structural elements. It becomes shallower from Vigdis West to Vigdis Middle. The relative positions of the Ness Formation and other sandstone rich formations along the faults control the OWC discrepancies.

Mechanism of Transit Time Increase and Its Interpretation After Water Injection into Reservoir M in the Lao Jun Miao Oil Field

Summary Reservoir M in the Lao Jun Miao oil field is a very massive sandstone oil reservoir about 60 m [200 ft] thick. Within the reservoir, there are no evident shale barriers and no interlayer standard water zones. This reservoir is classified as a fractured porous reservoir. The reservoir rocks have a high shale content; montmorillonite is the main clay mineralwith a maximum percentage content of up to 60%. After water injection, the sonic transit time was increased substantially in the flooded rather than in the nonflooded intervals. This paper gives an idea of the mechanism for the increase in sonic transit time in flooded intervals of the reservoir on the basis of the measurement and analysis of the noninvaded cores. Study results show that the increase in sonic transit time after flooding is linked to the rock texture in relation to the high montmorillonite content. It is well known that montmorillonite expands when it absorbs water and can plug the formation. However, it is possible to have better communication in the pores locally. These concepts are important and useful for better oilfield development and in the evaluation of the sweep efficiency of waterflooding. This paper also gives an in-house measurement technique for samples with high montmorillonite content. On the basis of core analysis and well testing data, we propose a comprehensive interpretation technique for determining flooding or nonflooding intervals that uses the transit time from sonic logging as the main data. Good results have been obtained.

Potiguar Basin: Geologic Model and Habitat of Oil of a Brazilian Equatorial Basin: ABSTRACT

The Potiguar basin integrates the eastern part of the Brazilian equatorial Atlantic-type margin. The rifting stage of this basin occurred during the Neocomian and Aptian. The drifting stage and sea-floor spreading began in the Late Albian. The rifting stage clearly was intracratonic during the Neocomian and is recognized as a mosaic of half-grabens trending mostly northeast-southwest and filled with syntectonic lacustrine siliciclastics. The half-graben pattern exhibits rotation of beds into the major fault zone, and the preserved uplifted margins display either paleostructures or paleogeomorphic features with hydrocarbons. A regional pre-Aptian unconformity preceded the Aptian proto-oceanic rifting stage which was characterized by syntectonic fluvio-deltaic sediments. Th Aptian tectonics were represented by reactivation of former lineaments superimposed by predominant east-west normal faulting. Structural highs during this stage are so far the most prolific oil accumulations. The most important source beds and reservoir rocks are both Neocomian and Aptian sediments. Geochemistry and hydrodynamics have shown that hydrocarbon migration was driven through fracture or fault zones in both Aptian or Albian plays. Lithofacies maps support this interpretation because pools occur whenever adjacent downthrown blocks present a high shale content. End_of_Article - Last_Page 475------------

A Stimulation Technique Using Only Nitrogen

Summary Nitrogen alone has demonstrated success as a fracturing fluid in reservoirs normally found sensitive to liquid systems. It has proved useful in shales of the Ohio Valley and West Virginia areas, and in similar lithology of the Fort Worth basin located in north central Texas. The fracture efficiency of nitrogen, as related to leakoff and flow capacity testing with no propping agent, has been investigated to analyze the effectiveness of nitrogen stimulation. Also, field data are presented that demonstrate successful results of the nitrogen technique in both oil and gas reservoirs. From the laboratory studies and field results, several conclusions were drawn concerning nitrogen stimulation. Of primary interest is that most of the width reduction in an unpropped fracture will occur in the early stage of production, which indicates a sharp decline of the well tow rate after a relatively short period. Introduction Nitrogen has been applied for many years in the stimulation process to enhance recovery of oil and gas. The properties of nitrogen, including its relative inertness, low solubility, and compressibility as well as other advantages, are well-documented. Although gaseous nitrogen was introduced initially in the oil field to assist in drilling operations, it was eventually employed to complement and energize liquid or gelled treating fluids. In recent years, nitrogen has been used increasingly as a major part of foam fracturing systems. These foams can be prepared with a variety of base liquids and typically contain 60 to 90% nitrogen. Foam treatments are particularly beneficial in low-pressure gas wells and in water-sensitive reservoirs such as the shale formations described in this paper. Indeed, it appears that foam is one of the most suitable fluids for the stimulation of such formations. However, in certain lithological areas of the Devonian shale formation, namely Washington County (OH), little success with foam has been encountered. Thus, the use of nitrogen alone has been pursued as a less-damaging method of treatment. This stimulation technique, applied to more than 1,000 wells since 1979 has been found to have considerable merit. This paper discusses treatment design, case histories, and laboratory evidence that corroborate present success and encourage further interest in the use of nitrogen alone as a stimulation technique in these formations. Stimulation History Formations having a high shale content and natural fractures, such as those found in the Ohio Valley and the Fort Worth basin, have been difficult to stimulate. These formations are characterized by low flowing pressures and low permeability. The presence of these natural fractures is crucial to the economics of the well because they provide the needed drainage system for production. Furthermore, these formations are water-sensitive and have a tendency to clean up slowly following a stimulation treatment. For the ideal movement of fluids, such as is necessary for well productivity, the primary concern is to have a continuously fractured reservoir. Shale specimens also absorb moisture and upon drying become very brittle and unstable. This, too, is a determining factor in fracture-fluid selection. JPT P. 2165^