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SPE/EAGE European Unconventional Resources Conference & Exhibition - From Potential to Production
- Conference date: 20 Mar 2012 - 22 Mar 2012
- Location: Vienna, Austria
- Published: 20 March 2012
1 - 20 of 74 results
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Hydraulic Fracture Monitoring to Reservoir Simulation: Maximizing Value
Authors C.L. Cipolla, M.J. Williams, X. Weng, M. Mack and S. MaxwellHydraulic fracture monitoring with microseismic mapping is now routinely used to measure hydraulic fracture geometry, location, and complexity, providing an abundance of information that can be essential to optimizing stimulation treatments and well completions. Although microseismic mapping has added significant value in many different environments, we have yet to fully utilize microseismic data. Significant details can be extracted from microseismic measurements that, when integrated with other information, can improve the characterization of both the reservoir and the hydraulic fracture. In addition, microseismic data has yet to be quantitatively and routinely utilized in reservoir simulation, which is the key to optimization.
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Integrating Microseismic Mapping and Complex Fracture Modeling to Characterize Fracture Complexity
Authors C. Cipolla, X. Weng, M. Mack, U. Ganguly, H. Gu, O. Kresse and C. CohenMicroseismic mapping (MSM) has shown that the occurrence of complex fracture growth is much more common than initially anticipated and is becoming more prevalent with the increased development of unconventional reservoirs (shale-gas). The nature and degree of fracture complexity must be clearly understood to select the best stimulation design and completion strategy. Although MSM has provided significant insights into hydraulic fracture complexity, in many cases the interpretation of fracture growth has been limited due to the absence of evaluative and predictive hydraulic fracture models.
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A Practical Guide to Interpreting Microseismic Measurements
Authors C. Cipolla, S. Maxwell, M. Mack and R. DownieThousands of hydraulic fracture treatments have been monitored in the past ten years using microseismic mapping, providing a wealth of measurements that show a surprising degree of diversity in event patterns. Interpreting the microseismic data to determine the geometry and complexity of hydraulic fractures continues to be focused on visualization of the event patterns and qualitative estimates of the “stimulated volume”, which has led to wide variations and inconsistencies in interpretations. Comparing the energy input during a hydraulic fracture treatment and resultant energy released by microseismic events demonstrates that the seismic deformation is a very small portion of the total deformation. The vast majority of the energy is consumed in aseismic deformation (tensile opening) and fluid friction (Maxwell et al. 2008). Proper interpretation of microseismic measurements should account for both seismic and aseismic deformation, coupling the geomechanics of fracture opening and propagation with the shear failures that generate microseisms.
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Understanding Hydraulic Fracture Variability Through Integrating Microseismicity and Seismic Reservoir Characterization
Authors S.C. Maxwell, T. Pope, C. Cipolla, M. Mack, L. Trimbitasu, M. Norton and J. LeonardMicroseismic measurements were integrated with seismic reservoir characterization and injection data to investigate variability in the hydraulic fracture response between three horizontal wells in the Montney shale in NE British Columbia, Canada. When wells were close enough, hydraulic fractures were found to interact with pre-existing faults, which acted as a barrier to fracture growth, and resulted in relatively large-magnitude microseismicity.
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Maximize Placement of Wells and Production in Unconventional Reservoirs: Part 2
More LessOver the past decade, significant supplies of natural gas have been discovered in shale. While the development of new technologies has driven down the cost of gas extraction, pursuing natural gas in shale continues to be risky and capitalintensive.
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Stimulation Unlocks Coalbed Methane: Lessons Learned in India
Authors Shahvir Pooniwala and Baker HughesAlthough gas production from coalbed methane (CBM) wells has become an important source of energy in North America over last couple of decades, it still remains an upcoming area in India. India has the fourth-largest proven coal reserves in the world and therefore considerable prospects exist for exploration and exploitation of CBM. Development of CBM and other unconventional gas sources are currently a priority for India to meet its growing energy demand.
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An Advanced Multi-lateral Horizontal Well Coupled Coalbed Methane (CBM) Simulation Model and its Application in Qinshui Basin of China
Authors Shiyi Zheng and Lili XueProduction enhancement and ultimate recovery improvement have given multi-branch horizontal wells the advantage over the vertical wells in many CBM marginal reservoirs. However, it is relatively very expensive to drill a muti-branch horizontal well than the vertical one, which makes difficulties for the engineers to determine an economical feasibility of drilling the multi-branch horizontal well as well as to estimate the productivity.
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Hydraulic Fracture Production Optimization with a Pseudo-3D Model in Multi- layered Lithology
Authors Mei Yang, Peter P. Valk and Michael J. EconomidesSystematic design and optimization procedures for hydraulic fracturing are available using two-dimensional (2D) (with constant fracture height) and pseudo-three-dimensional (p-3D) models to maximize well production by optimizing fracture geometry, including fracture height, half-length and width. A multi-layered p-3D approach to design is proposed integrating Unified Fracture Design (UFD), fracture propagation models and Linear Elastic Fracture Mechanics (LEFM) relationship to generate optimized fracture geometry, including fracture height, width and half-length to achieve the maximized production. Containment layers are discretized to allow for plausible fracture heights when seeking convergence of fracture height and net pressure. UFD sizes the fracture geometry to physically optimize the hydraulically fractured well performance. The Proppant Number is a correlating parameter, which in turn provides the maximum dimensionless productivity index (JD) corresponding to the optimum dimensionless fracture conductivity, CfD. Once the latter is determined, the optimum fracture dimensions, i.e., fracture length and width, are set. However, UFD in its original form needs the ability to calculate the Proppant Number and that is possible only if fracture height is an input parameter and hence fraction of proppant ending up in the pay can be determined before the optimization. PKN or KGD fracture propagation models in design mode provide basic treatment parameters to achieve a known target length and also associated net pressure. Linear Elastic Fracture Mechanics (LEFM) relationship can be used to obtain fracture height associated to a given vertical pressure distribution via vertical stress profile and fracture toughness profile. This study considers the contributions of all layers to the stress intensity factor at the fracture tips to find the potential equilibrium height defined by the condition where the stress intensity factor minus fracture toughness difference changes sign (but not necessary becomes zero.) After an equilibrium height and the corresponding net pressure are found, an optimization is carried out to find target length and a 2D design model is used to calculate treatment parameters, first of all net pressure. The ultimate goal is to find a consistent pair of these two different sub-models; when the assumed pressure condition in the LEFM part coincides with the resulting pressure condition from the UFD/2D part. Parts of this work also allows for determining conditions to avoid propagating into unintended layers (i.e. gas cap and/or aquifer) or to assure coverage of intended layers (such as a non-perforated layer with recoverable hydrocarbon.)
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Processing and Interpretation of Density and Neutron Logs for the Evaluation of Coal Bed Methane Reservoirs
Authors J.A. Wetton and P.A.S. ElkingtonDensity and neutron well log processing algorithms designed for conventional oil and gas reservoirs are not optimum for coal bed methane evaluation. In particular the corrections applied to measured electron density values (to derive bulk density) assume a calcium carbonate rock matrix, and quantitative analysis of neutron porosity logs is hindered by low count rates in coal and a lack of published information regarding the sensitivity of the measurement to variations in coal composition. The thinly-bedded nature of many coals is an additional challenge. This paper describes a new log processing method that simultaneously enhances statistical precision and vertical resolution whilst seeking to avoid additional sensitivity to the borehole environment. It then describes a fast nuclear rock properties modelling application developed to study the sensitivity of density, photo-electric cross-section (Pe) and neutron porosity measurements to variations in coal chemistry. The model has been validated using an accurate (but slow) Monte Carlo particle transport code which has been extensively benchmarked in independently characterized test blocks. The findings are applied to high resolution log data acquired in wells drilled for the evaluation of coal bed methane reservoirs. The key parameter used in the transformation of electron to bulk density is investigated and optimum values suggested. The sensitivity of density and neutron porosity measurements to variations in the volumes and chemistry of organic material, mineral matter and moisture is determined, and it is shown that appropriately processed neutron porosity logs have usable sensitivity to such compositional variations. The inclusion of neutron porosity improves our ability to differentiate coal types from logs, and addresses an important source of uncertainty in the reconciliation of log and core density values; in so doing it helps improve estimates of in-situ coal properties and associated quality attributes including gas-in-place.
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Casing Centralization in Horizontal and Extended Reach Wells
Authors Alfredo Sanchez, Christian F. Brown and Whitney AdamsLong laterals being drilled today present new challenges in getting casing to bottom and achieving good zonal isolation. Casing centralizers play a key role in achieving these objectives and should be evaluated differently than they have been in the past. A comprehensive methodology for evaluating, selecting, and running casing centralizers is described. This method is based on analyzing downhole conditions (formation type, borehole stability, etc.) in conjunction with specific drilling practices (bottom hole assembly design, hole cleaning procedure, etc.) to arrive at an optimum casing centralization program that will meet cementing objectives. A manufacturer and an operator share their experience in the application of comprehensive centralization placement and torque and drag modeling. Also discussed is the evaluation and selection of casing centralizers including practices to increase the accuracy of these simulations. Particular emphasis is given to rotation while running and cementing casing. Post job analysis of actual rig data is discussed in an effort to arrive at more accurate friction factors for future wells. In addition, custom laboratory testing and evaluation of running and restoring forces of bow-type centralizers is discussed. The approach described in this paper can help reduce the compromise between getting casing to bottom and achieving good zonal isolation.
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Effects of Pore Structure to Electrical Properties in Tight Gas Reservoirs: Experimental Study
Authors Xiao-peng Liu, Xiao-xin Hu and Liang XiaoThe Archie’s equation lost its role in tight gas sands due to the complicated pore structure and strong heterogeneity. It’s a challenge to determine the input parameters in the Archie’s equation. In this paper, 36 core samples, which were drilled from tight gas sands in China, are chosen for resistivity and NMR laboratory measurements. Based on the experimental study of these core samples, the influence factors to electrical properties are concluded to reservoir porosity and the proportion of small pore components. When the porosity is higher than 25%, the relationship between the porosity and the formation factor illustrares a power function, this is coherent with the classical Archie’s equation. When the porosity is low, the statistic line of the porosity and the formation factor bend to the left. The relationship between the porosity and the formation factor is not a simple power function, the parameter of m is various and relevant to porosity. The relationship between the water saturation and the resistivity index is divergent, the saturation exponent n varies from 1.63 to 3.48. After analyzing the corresponding NMR laboratory measurement for the same core samples, an observation can be found that the saturation exponent is relevant to the proportion of small pore components. When core samples are dominant by the small core components, the corresponding saturation exponent is high, vice versa. To estimate reservoir initial water saturation accurately, the pore structure information must be considered.
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Lessons from History - Unlocking a New UK Shale Oil Play
Authors Ian Roche and Aurora Petroleum LimitedThe paper highlights how key results from historical exploration for conventional hydrocarbons, dating back over 70 years, led to the discovery of a new shale oil resource play in the UK. Early conventional exploration in the West Lancashire sub-basin, conducted by D’Arcy Exploration, a forerunner of BP, was focussed on areas of surface seepage, and resulted in the discovery of the shallow Formby oilfield in 1939. In the late 1940s and early 1950s, a number of deeper wells were drilled, without success, targeting a proposed large Carboniferous conventional trap, leakage from which was thought to be source of the shallow accumulation. Exploration of the offshore East Irish Sea Basin, in the 1970s to 1990s, resulted in numerous oil & gas discoveries in Triassic reservoirs, sourced directly from Visean- to Namurian-age pro-delta shale source rocks (including the Brigantian- to Pendleian-age Bowland Shale Formation) precluding the requirement for secondary migration from Carboniferous traps. Regional studies highlighting poor poroperm preservation in Carboniferous clastic reservoirs led to the further downgrading of Carboniferous prospectivity. The recent identification of an unconventional shale gas play in the West Lancashire sub-basin by Cuadrilla Resources, within the Bowland Shale Formation, has led to a re-evaluation of the Formby area. New palynological and geochemical analyses of the early wells, presented in this paper, confirm the presence of a thick, prospective, Bowland Shale in the south of the West Lancashire sub-basin. Evidence that, locally, the Bowland Shale has generated liquid hydrocarbons is proven by the presence of the Formby shallow oilfield and the numerous oil seeps and relict hydrocarbon columns in the area; opening up a new shale oil resource play. The cumulative results from decades of exploration has revealed the true, unconventional, nature of the Carboniferous “mother lode” sought initially by D’Arcy, thereby heralding a new chapter in the hydrocarbon exploration of the basin.
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Testing Tight Gas and Unconventional Formations and Determination of Closure Pressure
Authors M. Y. Soliman and Talal GamadiExperience indicates that applying the conventional testing techniques such as drawdown-buildup tests to unconventional reservoir may lead to non-unique answers. Diagnostic testing approach is now more commonly used in tight gas formations and unconventional reservoirs. Testing unconventional reservoirs, particularly hydrocarbon-bearing shale formations, presents considerable challenges. In addition determination of the fracture closure pressure is sometime elusive. This paper reviews those challenges faced in analysis of testing of tight gas and unconventional reservoirs both liquid and gas. Conventional testing and analysis methods, although applicable, are often impractical because of excessive test duration. Diagnostic fracture injection test (DFIT) has become the preferred option for unconventional formations. Several methods may be used for interpreting DFIT data. We examine those methods in detail and explore their relative strengths while interpreting field data. We also show ways to determine the fracture closure pressure under various reservoir and fracture conditions.
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Impact of Fracturing and Fracturing Techniques on Productivity of Unconventional Formations
Authors M. Y. Soliman, Johan Daal and Loyd EastUnlocking the potential of unconventional gas reservoirs can change the balance and future of the oil industry. Unconventional gas reservoirs can be tight-gas, coalbed methane (CBM), or shale reservoirs. Economic production of any of these three types requires the creation of multiple fractures from a long horizontal well. Fracturing horizontal wells presents several challenges regarding the rock mechanics, change of stresses around the created fractures, and fluid flow. New and reinterpreted laboratory experiments have shed new light on fracturing a horizontal well and the effect of how the well is completed on the fracturing process. The results could explain the presence of multiple fractures at the wellbore. These geomechanical issues could influence the fracturing process, especially in naturally fractured formations. This paper investigates the effect of various fracturing scenarios on the stress distribution around the fractures. Optimization of the number of fractures is also investigated from both fluid-flow and geomechanical points of view. Special attention is given to shale formations for two reasons—because of the great potential of shale formations, and because of the special characteristics that makes shale unique and challenging. Shale formations have ultra-low permeability that can be in the nanodarcy range. Shale formations are naturally fractured, and, depending on the carbon content, can have a significant amount of adsorbed gas. This paper also investigates the effect of gas adsorption on productivity. Field examples are presented.
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Petrophysical Parameters Evaluation in Unconventional Reservoirs by Well Logging and Mud Logging Data Interactive Correlation Method
Authors Hrvoje Jurčić, Zoran Čogelja and Srećko MaretićThe idea and interest of studying the unconventional hydrocarbon reservoirs in the Panonian Basin System, abbr. PBS, (the Drava, Mura and Zala Depressions) are achieved by defining the joint research project carried out by the multidisciplinary team of MOL and INA petroleum companies. This analysis is performed in the Croatian part of the Panonian Basin System (CPBS). Eight areas with potential existence of unconventional reservoirs were examined with focus on Tight Gas Sands and Gas Shales. The primary object in this project stage is the estimation of possible unconventional reserves of gas (or Original Gas in Place, abbr. OGIP). Reserves are defined by area and reservoir porosity, saturation and net pay. They are usually estimated from well logging data and core laboratory and hydrodynamic data. Some difficulties and inabilities of accurate, i.e. professionally acceptable reservoir evaluation, were noticed. The reason is inadequate or incomplete well logging suite and inadequate formation evaluation work flow. Therefore, evaluation concepts from unconventional reservoirs presented in North American petroleum provinces could not be directly applied in our case. It was inevitable to use other data source, especially the Mud Logging Data to quantify net pay and qualify saturation. The rate of penetration, abbr. ROP, gas indications while drilling, the presence of hydrocarbon in rock samples, fracture systems on cores, inflows, eruptions and mud losses as well as the interpretation of overpressure using D exponent, abbr. Dcs method, significantly facilitated the evaluation of necessary parameters. It is crucial to improve economics of hydrocarbon production from any basin through operational efficiency, well productivity as well as new analytical models. Here presented evaluation method of potential hydrocarbon reserves is applicable in any similar case. It provides a highly acceptable professional credibility and can be very useful in situations with incomplete and inadequate Well Logging Suite facilitating identification and categorization of unconventional reservoirs.
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Effect of Sand Lens Size and Hydraulic Fractures Parameters on Gas In Place Estimation Using 'P/Z vs Gp Method' in Tight Gas Reservoirs
Authors Hassan Bahrami, Reza Rezaee, Mofazzal Hossain, Geeno Murickan and Naqiuddin BasharudinLow permeability and complexities of rock formation in tight gas reservoirs make it more complicated to predict well production performance and estimate gas recovery. To produce from the unconventional reservoirs in the case that formation rock is not sensitive to damage caused by liquid invasion, hydraulic fracturing is the most common stimulation treatment to improve the production to the excepted economically rate. In term of reservoir geometry, tight sand formations are normally consisted by the stacks of isolated lenses of sand bodies that are separated by impermeable layers (e.g. shale). Each sand lens varies in shape and size and acts as a trap for original hydrocarbon accumulations. The sand lenses parameters such as length and width can play important role in controlling gas recovery from hydraulically fractured tight gas reservoirs. This study shows the effect of drainage pattern of the lenticular sand bodies on production performance, gas in place (GIP) estimation using P/Z vs Gp method, and ultimate gas recovery in tight gas formations. Numerical simulation approaches are used in order to understand the effect of hydraulic fracture parameters and also attribution of sand lens size and shape to the drainage pattern and gas recovery in hydraulically fractured tight sand gas reservoirs. The results highlighted that in tight gas reservoirs, sand lens size in the direction perpendicular to hydraulic fracture wings has the major impact on gas recovery. Drainage of gas from the reservoirs is controlled by the sand lens width, and the size of sand lenses in the direction parallel to the hydraulic fracture wings does not have significant effect on gas recovery. The drainage area of the tight gas reservoirs is limited to the area perpendicular to the hydraulic fractures wings, and therefore P/Z vs Gp method may underestimate the value of GIP calculated for the lenticular/elliptical shape sand lenses.
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Using Deep Azimuthal Resistivity and 3D Seismic for Optimal Horizontal Well Placement: An Integrated Approach, Nipisi Field, Western Canada
Authors Sheyore John Omovie, Warren Pearson, Heiko Homburg, Ela Manuel and Pascal LuxeyA major challenge facing the oil industry is optimizing horizontal wellbore placement in a reservoir. Uncertainty in the predrill geological model and seismic interpretation may lead to the well being placed in non-reservoir, or steering the well out of the prospective formation. This can lead to lower well performance or the requirement to sidetrack the wellbore, both of which directly impact the profitability of the operation. The Nipisi D Pool produces oil from the Middle Devonian Slave Point Formation, a regionally extensive carbonate bank characterized by low permeability limestone reservoir. The advent of horizontal drilling (HZ) and completion technologies has elevated this reservoir to a top tier tight oil resource play. Although HZ drilling provides a cost effective means to reservoir development, maximizing reservoir penetration while avoiding the unstable shale above the Slave Point are imperative. Structural definition of the reservoir is provided by 3D seismic coverage. This provides a good predrill estimate of wellbore trajectory, however is limited in its vertical accuracy, as well as definition of small-throw faults that do not appear to be imaged on the seismic data. These two limitations introduce a real risk of drilling out of the productive zone. Using the contrast in resistivity between the productive carbonate reservoir and the low resistivity Waterways shale which overlies it, deploying Measurement-While Drilling (MWD) deep azimuthal resistivity tools provided the operator with higher resolution measurements to detect the top of reservoir and keeping the wellbore within the desired reservoir. This paper focuses on the integration of geological/3D seismic mapping and MWD azimuthal resistivity for optimal HZ well placement in a tight limestone reservoir, as well as the limitations of each technology when used in isolation. It illustrates how utilizing this approach the operator was able to achieve 100% reservoir exposure.
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Numerical Investigation of Hydraulic Fracturing Process and Sensitivity to Reservoir Properties and Operation Variables
Authors Natthapon Putthaworapoom, Jennifer L. Miskimins and Hossein KazemiAlthough a stimulation technique, the hydraulic fracturing process can also cause damage to the reservoir in a variety of ways. These damage mechanisms cannot be completely eliminated, but by careful examination of their individual characteristics and effects on production, focus can be placed on minimizing the most critical factors. This paper presents the results of a sensitivity study of numerous reservoir properties and operational control variables on fracture effectiveness and production from a fractured gas well. Simulations are based on a newly developed mathematical model for hydraulic fracture propagation and cleanup processes, combined with reservoir simulation. The numerical simulation model considers a three-dimensional reservoir which can either be homogenous or heterogeneous. The created fracture is extended with time and the corresponding leak-off effects on the near wellbore and far-field area are assessed. Two-phase flow equations, both in the fracture and in the surrounding matrix, are used to evaluate behavior during the fracture propagation and production/clean-up periods. The developed simulation model is validated by history matching with actual field performance from a fractured gas well. The history matched results are used as a base case for the study. The sensitivity results show the creation of different leak-off profiles and the effectiveness of corresponding cleanup processes. Results indicate that shut-in time between end of fracture propagation and beginning of flowback is critical due to imbibition of fracturing fluids. Additionally, heterogeneity of the reservoir has a significant effect on cleanup profiles. Not only does that this study provide significant insight into phenomena happening on the fracture face and inside the reservoir, it and the developed simulator can also be used as a tool for hydraulic fracturing design or post-stimulation evaluation.
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Overcoming Drilling Challenges in the Marcellus Unconventional Shale Play Using a New Steerable Motor with Optimized Design
Authors Wilfredo Davila, Azar Azizov, Sandeep Janwadkar, Anthony Jones, John Fabian and Tom RowanAlthough drilling horizontal wells in US-land unconventional shale plays has increased exponentially in the last few years, maximizing well productivity and improving drilling efficiency remains a major challenge. Well placement in the sweet spot and extended laterals help maximize productivity. Drilling a curve with higher dogleg severity (DLS) reduces its verticalsection and maximizes the length of subsequent lateral section in the productive zone. Wells in US shale plays demand a DLS of 10 to 14 deg/100 ft, but achieving high DLS presents numerous drilling challenges: rotating a steerable motor with a high adjustable kick-off sub (AKO) angle could result in bottomhole assembly (BHA) fatigue failure and premature damage to bit; drilling in oriented mode limits the transfer of weight to the bit, reducing the rate-of-penetration (ROP). These challenges led to the development and successful testing of a new steerable optimized design motor (ODM) with a short bit-to-bend (BTB) distance. In some cases, the ODM drilled all sections, including high-DLS curves, tangents and laterals with precise directional control and well placement with one BHA. Using the ODM helped the operator achieve higher build rates at lower AKO angle settings; rotate the BHA in well profiles where previously used motors could be operated only in slide mode, and maximize the length of curve interval drilled in rotary mode at higher rotations per minute (RPM). The new system significantly improved drilling performance with excellent directional control. Drilling high-DLS curves increased the length of laterals, enabling additional recovery of gas. This paper discusses the design, modeling and results of horizontal type wells drilled using the steerable ODM in the Marcellus unconventional shale play.
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Lab NMR Study on Adsorption/Condensation of Hydrocarbon in Smectite Clay
Authors Jillin Zhang, Jin-Hong Chen and Carl EdwardsSignificant amounts of gas accumulations exist in unconventional gas plays. Current understanding held that in unconventional shale plays, natural gas was stored as “free” gas in pore spaces and as an “adsorbed” phase on clay minerals and surface of organic pores material. The adsorption of methane has been confirmed in lab experiments in high-pressured gas chambers. Our lab experiments indicated that hexane vapor could be adsorbed onto organic-rich shale core samples through capillary condensation and the signal could be detected by Nuclear Magnetic Resonance (NMR) instruments. This study further examines the capillary condensation of hexane vapor into clay minerals and the NMR response. Smectite samples from the Clay Minerals Society were used in the experiments. Two types of capillary condensation experiments were conducted: one with water vapor and the other with hexane vapor, both at room conditions. Weight gains indicated that some of the vapor condensed in the loose powder of smectite clay. NMR experiments were performed on vaporsaturated samples using a Maran 2 MHz spectrometer with an inter-echo time of 300 μsec. The T2 distributions of the water-vapor and hexane vapor-saturated smectite clay were both unimodal. The water vaporsaturated sample showed a T2 at 0.5 ms, while the hexane vapor-saturated sample showed a T2 between 1 and 6 ms. This was likely due to the fact that the smectite crystallites have a small charge that has a more pronounced effect on polarized molecules such as water, than on non-polarized molecules such as hexane.
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