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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 - 50 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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Post-Frac Production Analysis of Horizontal Completions in CANA Woodford Shale
Authors Bill Grieser and Chris TalleyThe Oklahoma Woodford shale has produced hydrocarbon since the early 1950s. Recent horizontal development using multistage fracture stimulations of the CANA Woodford located in the Anadarko basin has resulted in high initial gas-flow rates, and substantial liquid production when in the gas-condensate window. Completion type and strategy have changed from methods used during the initial discovery phase in 2005 to the present development phase in 2011. This paper compares completion parameters used for a given time period to the individual production trend, using a linear flow transient model. Using the normalized reciprocal rate/pressure versus the square root of time plot, the stimulated reservoir volume (SRV), effective fracture half-lengths, reservoir-system permeability (km h), productivity index (PI), and overall stimulation effectiveness were determined. Ranking of fracture-stimulation effectiveness is made from production-derived bulk reservoir properties, including • The product of fracture-surface area and square root of the effective formation permeability (Ackm 1/2). • Apparent skin (s’) from the b’ intercept of the square root of time plot; an indication of skin. • Hydrocarbon pore volume (HCPV). The results are summarized in tables showing the effect of completion factors on the production outcome.
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Silurian Lithofacies and Paleogeography in Central and Eastern Europe: Implications for Shale Gas Exploration
Authors Gabor TARI, Pawel POPRAWA and Piotr KRZYWIECThe present day collage of various Silurian basin fragments in Central and Eastern Europe is the result of several orogenic and rifting/drifting episodes. The proper paleogeographic reconstruction of a single, very large Silurian foredeep basin in the context of regional geology has a major impact on the ongoing unconventional shale gas exploration efforts in the broader region. The distal segments of a large Silurian foredeep basin, as the result of Caledonian orogeny, can be reasonably followed along strike from NW to SE, from Poland to Ukraine and Moldavia, all the way to the Black Sea coast. The foredeep basin sequence is onlapping to the NE on top of various Lower Paleozoic and basement units. The flexural origin of the basin, besides the typical subsidence curves, is also supported by the distribution of lithofacies such as deepwater shales in the center, neritic carbonates on the foreland perimeter and clastic turbidites on the southwestern flank. The proximal parts of the Silurian basin are much harder to reconstruct. Two major opening episodes are critical for restoring the Silurian paleogeography. One of them is the reconstruction of the conjugate Bohemian (Austria, Czechia, Slovakia and Poland) and Moesian (Romania and Bulgaria) passive margins prior to the opening of the Jurassic Magura Ocean. The other important step for any regional-scale Silurian reconstruction is the closing of the Cretaceous western Black Sea Basin between the conjugate margins of Moldavia/Romania/Bulgaria and Turkey.
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Diagnosing Fracture Network Pattern and Flow Regime Aids Production Performance Analysis in Unconventional Oil Reservoirs
Authors Faisal Rasdi and Lifu ChuMany tight or shale gas wells exhibit a linear flow regime that can last for years. However, production analysis in unconventional oil reservoirs, such as the Bakken, shows that the linear flow regime is not the only dominant flow regime. Field data suggest that the duration of boundary-dominated flow influenced by the stimulated-reservoir volume (SRV) and compound-linear flow generally overshadow the early-time linear flow regime. Depending on the fracture network or SRV patterns, formation linear flow in unconventional oil reservoirs may only last for a few months but contribute about 30% of the total estimated ultimate recovery (EUR). This study develops a procedure for identification of different fracture network patterns and inference of related flow parameters based on analytical methods. The reservoir description so derived is transported to a numerical reservoir-flow simulation model to capture the effects of compaction, multiphase flow behavior, and various flow regimes in an unconventional oil reservoir system. This coupled approach helps illuminate reservoir performance, which allows insights into history matching. In particular, we demonstrate (a) fracture network patterns and flow regime diagnosis through rate-transient analysis; (b) coupled numerical reservoir simulation with analytical modeling results for performance-constrained history matching; (c) sensitivity analysis on the heterogeneity effect, compaction effect, and multiphase flow effects; and (d) field application of the proposed procedure on Bakken wells. This proposed method demonstrates that analytical methods should be used before undertaking a detailed numerical reservoirflow simulation study. This understanding paves the way for much improved reservoir characterization in unconventional oil reservoirs.
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Novel Traceable Proppant Enables Propped Frac Height Measurement While Reducing the Environmental Impact
Authors Pedro Saldungaray, Terry Palisch and Robert DuenckelFracture height is typically used by fracturing engineers to calibrate propagation models. Having an accurate height measurement reduces the uncertainty and non uniqueness of fracture pressure matching, better determining placed frac length and width, stress profile across the target zone and its boundaries, and fracture containment. This is particularly important when there is concern with vertical penetration into an unwanted zone, or determining adequate zonal coverage and development of reserves. In most cases, fracture height is measured by the industry through the use of radioactive tracers which are blended into the proppant at the wellsite. Clearly this can present both a safety and environmental hazard. Furthermore, in some regions of the world operators are prohibited from using these hazardous materials altogether. This paper presents an innovative, environmentally responsible proppant detection technology and the associated logging techniques for propped height measurement and/or proppant placement. Its non-radioactive nature eliminates the risks and difficulties inherent to other tracing methods. Furthermore, being inert the proppant has no half-life time limitation and is permanently detectable. In this manner it provides the flexibility of conducting multiple post-frac logging at any time after fracturing for initial assessment or to identify intervals for re-stimulation further down the life in the well. The tracing capability doesn’t interfere with the proppant physical properties, crucially its strength and conductivity, assuring adequate performance. The theory and physical principles of the technology are discussed in detail and supported by case histories of its application in various environments around the world.
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The Challenges of Shale Gas Exploration and Appraisal in Europe and North Africa
Authors Christopher Burns, Adrian Topham and Ramin LakaniThe shale gas revolution on North America has created an incentive for the rest of the world to chase this challenging hydrocarbon resource. Currently around 44% of the 20.6 tcf annual gas production in the US occurs from unconventional resources, with this forecast to rise to 65% by 2020. The pitfalls and challenges faced by North American development projects provide a wealth of experience, which can be used to understand how we can apply technology more effectively in Europe and North Africa. However, there are differences in both operating environments and gas markets between North America and Europe and North Africa, and we aim to highlight these differences as well as the similarities. Unconventional oil and gas projects in Europe and North Africa are currently at an early stage of their life cycle, exploration and appraisal. We identify the following key challenges for the European region: • The potential spread of the North American unconventional gas revolution to Europe and North Africa could create competition and depress gas prices. Reduced gas prices and increased costs will considerably reduce the margin for error in exploring for unconventional gas. Therefore there is a need to apply technology effectively, to avoid having to learn “by the drill bit”. • A lack of infrastructure and specialised equipment, particularly in North Africa, leading to a higher cost base for developing the region’s unconventional resources. • The regulatory environment in Europe is not presently conducive to development of shale gas resources together with the negative public perception of the environmental risk associated with shale gas development. Aside from these medium to long term challenges, Europe at present is facing a more critical short term challenge: the need to prove the concept by completing and producing the first economic shale gas wells. To overcome these challenges, operating and service companies need to apply technology effectively and efficiently at an early stage in shale resource development. This paper offers a potential approach and methodology first to evaluate unconventional resources, and secondly to apply technology to unlock their potential. An integrated oilfield service approach could make unconventional gas appraisal outside of North America economically feasible and sustainable. As in conventional reservoir developments, detailed reservoir description can be used to optimize reservoir penetrations 2 SPE 151868 and predict well performance. In the second part of this paper we discuss how a Shale Engineering workflow that will improve the effectiveness of interaction between operators and service companies, and enable commercial production of unconventional resources outside North America. Unconventional reservoirs are defined for the purposes of this paper as oil and gas reservoirs that exhibit low permeability such that hydrocarbons cannot be produced at economic rates without stimulation of the reservoir.
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Understanding Volumes, Economics and Risk Mitigation in Unconventional Gas Projects
Authors Melvyn R. Giles, Daniel Nevin, Bud Johnston and Mark HollandersA great deal has been written on the volumes of unconventional gas trapped in the subsurface, this paper examines: 1) The relationship between the huge GIIP volumes, technically recoverable volumes and economically recoverable volumes 2) The barriers to achieving economically viable projects 3) Lifecycle and drivers for creating economically viable projects 4) The use of decline curves to estimate the productivity and the pitfalls associated with their use 5) Strategies for mitigation of economic risk in taking an exploration project through to development New unconventional gas projects all come with considerable uncertainties and therefore risk, but careful de-risking strategies enable companies to steer their way toward clear go/no go decisions at multiple points in the lifecycle enabling them to progress with minimum exposure.
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Integrating Geology, Hydraulic Fracturing Modeling, and Reservoir Simulation in the Evaluation of Complex Fluvial Tight Gas Reservoirs
Hydrocarbon resources such as tight sands have become one of the most sought after types of unconventional plays, given the extensive amounts of gas they contain. In order to access these reserves, the industry is focused on improving hydraulic fracturing techniques with the purpose of increasing gas recovery. However, proper reservoir management practices, in conjunction with improved completion processes, are also key factors for maximizing these gas reserves. Additionally, reservoir understanding becomes even more relevant when dealing with reservoirs deposited in complex fluvial environments. This paper discusses a study that integrates the accurate stratigraphy and detailed reservoir characterization of a 160-acre 3D fluvial geologic outcrop model populated with analog producing field reservoir properties with detailed hydraulic fracturing modeling to better understand the effects that fluvial depositional environments have on hydraulic fracture growth. Subsequently, the detailed hydraulic fracturing growth parameters are implemented in a robust 3D reservoir simulation model, representing the heterogeneous geologic environment. Reservoir simulation is then used to determine the dynamic flow conditions associated with the fluvial geologic model with the ultimate goal of determining optimum reserve recovery practices such as well spacing and placement, hydraulic fracture design components, etc. The methodology applied in this study, which starts with the 3D outcrop mapping and characterization, followed by the development of a geostatistical model, hydraulic fracturing modeling, and reservoir simulation is presented. Three different cases, consisting of various well locations and spacing, are described. Results show that the continuity of sand bodies in the near wellbore vicinity, whether part of the completion interval or not, is critical to the ultimate reserve recovery and is a function of the hydraulic fracture growth pattern. Additionally, amalgamation of the sandstone bodies, which also affects the hydraulic fracture growth patterns, has a strong effect on gas recoveries. Finally, for the cases reviewed, the benefits of infill drilling were mainly obvious in reserve acceleration versus reserve addition.
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Unconventional Shale Play Selective Fracturing Using Multilateral Technology
Authors Doug G. Durst and Mario VentoDrilling, completing, and fracturing of unconventional formation wells in North America are now commonplace and will begin to play a role in the future of natural gas production in the international market. What is not as common is to drill, complete, and frac multiple lateral branches from a single main wellbore. Multilateral wells have been routinely drilled for a number of applications, and shale plays are a natural progression for its use. Augmenting a multilateral well with selective fracturing of each leg is as straightforward as fracing a single horizontal well. Using conventional equipment and techniques, a multilateral well (with any number of laterals) can accommodate any type of fracturing system and program with pressures up to 12,500 psi with complete isolation of the lateral junction(s). In this project, a plug-and-perf system was used to address ten plus intervals in each leg, with average stimulation pressures up to 9,000 psi. Multilateral solutions provide the means to work within a limited surface access, generating a reduced footprint while draining a much larger volume of the reservoir from a single-surface location. This poses a significant advantage when drilling in sensitive or restricted locations, populated areas, and where land issues restrict access to multiple drilling locations. Additionally, the cost and impact of large drilling pads or multiple well sites is avoided. This paper will discuss the implementation and execution of this project, the first dual-lateral well by any operator in the Granite Wash at vertical depths over 12,000 ft. This well targeted two different sections of the Granite Wash (a complex series of sands, shales, and siltstones that run from the northern Texas Panhandle into Oklahoma) from a single main wellbore, with commingled production rates doubling typical single horizontal well performance.
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Extending Reamer Life and Improving Drilling Performance by Optimizing Neutral Points in Bottomhole Assemblies
Authors Roxann J Krishingee, Karl Ulmer and Byron PoseyWith the development in drilling technology, operators are now drilling further into unknown temperature and pressure regimes, extending the typical well depth to limits never seen before. To deal with these unseen depths, wellbores are being re-designed with more casing strings. Consequently, under-reamers are being used much more frequently to help achieve the optimum hole size for casing. In bottomhole assemblies (BHAs) with under-reamers it is not unusual to have two neutral points in the assembly, creating a transition zone between both neutral points. To comprehend the effects of placing a reamer in this transition zone, some field cases with reamers placed in this zone were studied. Based on the findings, the reaming bottomhole assembly was optimized to eliminate dual neutral points, which resulted in extended under-reamer life. This paper discusses the benefits of optimizing hole-opener placement in regards to neutral points and the transition zone. Some precautionary procedures are mentioned that can be implemented to optimize bottomhole assemblies that include reamers, reduce BHA failures and improve drilling efficiency.
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A New Approach to Biocide Application Provides Improved Efficiency in Fracturing Fluids
Authors Jeff Dawson and Marodi WoodHydraulic fracturing of oil and gas wells requires high volumes of water. Often these waters originate from rivers, lakes, ponds, and recovered water from previous fracturing treatments. The waters are often infested with aerobic and anaerobic bacteria that can cause multiple problems. The include degradation of fracturing chemicals, down-hole corrosion, biological-based H2S generation, and down-hole flow-impairment due to slime producing bacteria.
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Evaluation of Recovery Performance of Miscible Displacement and WAG Processes in Tight Oil Formations
Authors S.M. Ghaderi, C.R. Clarkson, S. Chen and D. KavianiRecent advances in well design and production techniques have brought considerable attention to exploitation of tight (low permeability, absolute permeability <1 mD) oil resources. Drilling of long horizontal wells and deployment of hydraulic fractures along these wells (multi-fractured horizontal wells) can substantially improve the primary production rates from such reservoirs. Nevertheless, the low effective permeability of the formation to oil hinders the sustainability of favorable oil rates and at some point applying some EOR technique becomes inevitable. In the current study, CO2 miscible flooding and WAG processes in a tight oil reservoir are investigated. Although several studies have investigated different aspects of the process in conventional oil plays, the design of an effective scheme in tight oil formations is more complex. These complexities are related to the proper design of the fractures (half-length, permeability, direction (transverse vs. longitudinal), etc.) and their relative arrangement in producers and injectors and the operational constraints on each well or segment of the well. In this work, we utilize an innovative EOR scheme design where multi-fractured horizontal wells are used for both injection and production, and the hydraulic fracturing stages are staggered to delay breakthrough and improve sweep efficiency. For a set of defined parameters, compositional simulations are conducted to optimize the WAG ratio and cycle length and injection starting point (in time) for the model. The recovery associated with EOR is compared with its corresponding base case model in which all wells are producing under primary recovery for the whole life of the reservoir. The results of this study show that the primary recovery factors (5-15%) can be increased to 25-35% under optimum flooding conditions, considering a reasonable economic framework.
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New Inflow Performance Relationship for Coalbed Methane Wells Qihong Feng,
Authors Qihong Feng, Hongfu Shi, Xianmin Zhang, Peng Du and Jiyuan Zhangthe presence of permeability dynamics with pressure based upon P&M or Shi model. A second objective of this paper is to develop an approach for multiphase flow which requires a relationship between relative permeability and pressure, analogous to Fetkovich’s method for oil and gas flow. The methodology is further validated with field data from Qinshui Basin in China. The results indicated that the tool proposed here provides reservoir enginners with a quicker and easier way to estimate the performance of coalbed methane well.
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Modelling of Hydraulic Flow Characteristics in Depleting Tight Gas Reservoirs
Authors D. Albrecht and V. ReitenbachFluid flow properties of tight Rotliegend sanstones show a strong sensitivity to stress conditions. To improve the understanding how fluid flow properties depend on the stress situation experimental measurements have been conducted on low to ultra-low Rotliegend sandstone samples from a North-German gas reservoir under simulated reservoir stress conditions. The measurements have been performed in the project DGMK 593-9/4 in the framework of the tight gas program of the DGMK (German Society for Petroleum and Coal Science and Technology). From the results of the experiments models could be derived, which describe the stress dependency of permeability and porosity. The experimental study improves the understanding of stress dependence behavior of low permeable North- German sandstones and provides relevant reference data for simulation of flow processes. The correlation models based on the experimental results presented enable the evaluation of representative in-situ effective stress, permeability and porosity in low permeable Rotliegend sandstones from routine laboratory permeability and porosity data as well as depletion effects during the gas production.
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Advances in Measurement Standards and Flow Properties Measurements for Tight Rocks such as Shales
Authors S. Sinha, E.M. Braun, Q.R. Passey, S.A. Leonardi, A.C. Wood III, T. Zirkle, J.A. Boros and R.A. KudvaDetermination of permeability of unconventional reservoirs is critical for reservoir characterization, forecasting production, determination of well spacing, designing hydraulic fracture treatments, and a number of other applications. In many unconventional reservoirs, gas is produced from tight rocks such as shale. Currently the most commonly used industry method for measuring permeability is the Gas Research Institute (GRI) technique, or its variants, which involve the use of crushed samples. The accuracy of such techniques, however, is questionable because of a number of inadequacies such as the absence of reservoir overburden stress while conducting these measurements. In addition to questionable accuracy of crushed rock techniques, prior studies have indicated that there is significant variability in results reported by different laboratories that utilize crushed-rock technique to measure permeability on shale samples. Alternate methods are required to obtain accurate and consistent data for tight rocks such as shales. In this paper we discuss a robust steady-state technique for measuring permeability on intact tight rock samples under reservoir overburden stress. Permeability measurement standards for low permeability samples are critical for obtaining consistent results from different laboratories making such measurements, regardless of the method used for measuring permeability. In this paper we present permeability measurement standards developed based on first principles that serve as the “ground-truth” for permeability in the 10 – 10,000 nanoDarcy range. These standards can be used to calibrate any permeability measurement apparatus used to measure permeability on intact tight rock samples such as shales, to enable delivery of consistent results across different laboratories conducting measurements on intact tight rock samples.
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High-Resolution LWD Images Used to Optimize Completions in Unconventional Play - North America
The Barnett Shale is one of the most mature and prolific natural gas fields in North America. It has a multi-trillion-cubic-feet equivalent upside potential but well completions are not resulting in consistent production within the same section or across the unconventional play. As infield drilling increases, collision and encroachment from well to well due from offset induced fractures, natural fractures, faults, and internal stresses are becoming more important to characterize and map. The operator and the service provider teamed up and used high-resolution images to optimize perforation placement, redesign stimulation, and stage placement. To overcome these challenges, high-resolution, state-of-the-art logging-while-drilling (LWD) imaging tools were used to acquire images on a well drilled between two 600-ft (182.9-m) offset wells. These images are also being used to map fracture systems, faults, and stresses in the field. With the knowledge obtained from these LWD images, completions are now being redesigned to incorporate this information for optimizing fracture treatments. The paper will provide examples of high-resolution images generated which were used to determine untreated formation matrix, and avoid faults for possible water production. Proper interpretations of these images and other advanced technologies have enabled operators to increase well productivity up to 20% as compared to offset wells. These advanced technologies have been implemented and used in over 250 wells with excellent results. The images will be used in the future to determine which wells would be the best candidates for recompletions. The lessons learned can be applied to most unconventional plays around the world.
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Assessment of an Unusual European Shale Gas Play: The Cambro-Ordovician Alum Shale, Southern Sweden
Authors Wilfred Pool, Mark Geluk, Janneke Abels, Graham Tiley, Erdem Idiz and Elise LeenaartsIn 2008 Shell obtained two licenses for unconventional gas exploration in the Skne region of southern Sweden, with a total size of 2500 km2 (600,000 ac). The objective was the Cambro-Ordovician Alum Shale, one of the thickest and richest marine source rocks in onshore northern Europe. The licenses covered the Hllviken Graben and the Colonus Shale Trough. In both areas the Alum Shale had been encountered in older wells, with a thickness of up to 90 m and TOC values up to 15%. Maturities of up to 2% Vre were considered encouraging for a shale gas play. Relative high quartz contents suggested good fraccability of the shales. All data was obtained through public sources. Identified risks were the uncertain timing of hydrocarbon generation and the position of the licenses adjacent to the Trans-European Suture Zone where several phases of fault movement have a risk for actually retaining the hydrocarbons. The derisking strategy for this opportunity was based on both technical and non-technical aspects. Aim was to collect geological and geophysical data to constrain depth and thickness of the shale and to identify potential dolerite dykes. In addition, well data were needed to establish rock properties and gas content. The external environment, especially concerns from the people in Skne regarding the visual impact of activities and potential impact of drilling activities on the aquifers and on the tourism industry have resulted in extensive engagements with stakeholders and specific requirements around seismic acquisition (low impact), site preparation and operations (e.g. small rig, different lighting). 80 km of 2D seismic was acquired in 2008 and three wells, with a final depth of around 1000 m, were drilled in 2009 to mid 2010. The Alum shale was fully cored and the well sites have been restored. Thickness, richness and maturity of the Alum were as predicted although the basin was shallower than previously anticipated. Canister desorption tests, however, indicated that the shales have only low gas saturation. This significantly increased the risk for a viable shale gas play and therefore the licenses were not renewed after the initial 3 year period.
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Perforating on Wireline – Weak-Point Load Prediction
Authors Carlos Baumann, Marcia Benavidez, Andy Martin, Alan Salsman and Harvey WilliamsThousands of wireline conveyed perforating jobs are executed every month around the world; however certain jobs have a higher risk of weak-point breakage due to dynamic pressure loads, known as gunshock loads. Gunshock loads result from pressure waves in fluids and stress waves in structural components. Perforating under all conditions (i.e. static/dynamic overbalance or underbalance) can produce pressure waves and/or reservoir surge of large magnitude leading to wireline weak-point (WWP) failures and/or cable damage. These risks are assessed as part of the job preparations. In this paper we focused on Dynamic Underbalance (DUB) because perforating with DUB can deliver clean perforations with very low risk of gunshock damage when properly planned. For any perforating job on wireline, the magnitude and duration of pressure and stress waves depend on job parameters that can be adjusted, such as type and size of guns, shaped charges, gun loading layout, wellbore fluid, placement of packers and plugs, and cable size. For perforation damage removal we need a job design to generate a DUB of enough magnitude, using the right gun types and loading to produce a DUB of large-amplitude but short-duration, thus removing perforating rock damage while minimizing gunshock loads on the WWP. Perforating job designs are evaluated with software that predicts the transient fluid pressure waves in the wellbore and the associated structural loads on the cable and tools. All aspects of well perforating are modeled including gun filling, wellbore pressure waves, wellbore and reservoir fluid flow, and the dynamics of all relevant solid components like cable, shock absorbers, tools, and guns. When planning perforation jobs that may have a significant risk of weak-point breakage, we predict the peak dynamic loads on the cable and weak-point during the design process, and when necessary we make design modifications to reduce the peak load on the WWP. The software’s predictive capabilities are demonstrated by comparing downhole fast gauge pressure data (110,000 data points per sec), shock absorber deformation, and cable tension logs with the corresponding simulated values. Fast gauge pressure data from perforation jobs shows that the software predictions are sufficiently accurate to evaluate the gunstring dynamics and the associated peak tension load on the WWP as part of the job planning process. Residual deformation of shock absorbers correlate well with predicated peak axial loads at the WWP, and available cable tension logs from vertical wells show that the cable surface tension is well predicted. The simulation software described in this paper is used to minimize the risk of unexpected release of tools and guns due to perforating dynamic loads, thereby minimizing the probability of non-productive time (NPT) and fishing operations.
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Benchmarking Unconventional Well Performance Predictions
Authors Rainer van den Bosch and Antonio Paivachmarking of the system’s prediction capability for each metric. In adding to the analytical toolkit, the key objective of this benchmarking method is to support decision making on an ongoing development, well before the entire program has been executed. Possible applications include: • Early confirmation of successful well placement. • Early indication of the impact on well performance as a result of changes to drilling and stimulation procedures. • A ‘conditional probabilistic' outlook of long-term well behavior to better define well/field economic scenarios and to guide reserve bookings. This process has been developed using public data from the data rich fields Barnett in Texas, Fayetteville in Arkansas and Woodford in Oklahoma. This process is also viable for plays with scarce data and is able to be refined with increasing data availability.
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A New Approach for Numerical Modeling of Hydraulic Fracture Propagation in Naturally Fractured Reservoirs
Authors R. Keshavarzi and S. MohammadiHydraulic fracturing of a naturally fractured reservoir is a challenge for petroleum industry, as fractures can have complex growth patterns when propagating in systems of natural fractures that leads to significant diversion of hydraulic fracture paths due to intersection with natural fractures which causes difficulties in proppant transport. In this study, an eXtended Finite Element Method (XFEM) model has been developed to account for hydraulic fracture propagation and interaction with natural fracture in naturally fractured reservoirs including fractures intersection criteria into the model. It is assumed that fractures are propagating in an elastic medium under plane strain and quasi-static conditions. The results indicate that hydraulic fracture diversion before and after intersecting with natural fracture is strongly controlled by the in-situ horizontal differential stress and the orientation of the natural fractures as well as hydraulic fracture net pressure. It is observed that hydraulic fracture net pressure increase leads to decreasing induced fracture diversion and in-situ horizontal differential stress decrease results in increasing induced fracture diversion before intersecting with natural fracture. In addition, potential debonding of sealed natural fracture in the near-tip region of a propagating hydraulic fracture before fractures intersection has been modeled which is one of the phenomena that has been rarely taken into account, as debonding of natural fracture before fractures intersection is of great importance that may lead to diverting the induced fracture into double-deflection in natural fracture and can explain hydraulic fracture behaviors due to interaction with natural fracture at different conditions. Also, it’s been observed that at low angles of approach with low to high differential stress, the induced hydraulic fracture opens the natural fracture while at high to medium angles of approach, natural fracture opening and crossing both are observed depending on the differential stress. Comparison of the numerical and experimental studies results has shown good agreement.
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Understanding Hydraulic Fracture Stimulated Horizontal Eagle Ford Completions
Authors Robert Shelley, Luke Saugier, Wadhah Al-Tailji, Nijat Guliyev and Koras ShahThis paper will present results from a modeling effort to derive best practices for the completion of hydraulically fractured horizontal Eagle Ford wells. The well, reservoir, completion/frac and production information used in this evaluation were provided by an operator from a five-county area in Texas. Hydraulically fractured horizontal completions pose significant modeling and evaluation challenges. This is primarily due to two issues: 1) lack of well-specific data about the reservoir/rock properties, and 2) improper assumptions used in the modeling process. As shown in this paper, a data-driven approach to modeling these completions provides a much needed pragmatic perspective, identifies high-impact parameters and provides direction about how to improve the effectiveness of these complex completions. Sensitivities performed on the predictive data model indicate that well-to-well variation in reservoir quality and geology has a dominant effect on Eagle Ford production. In addition, issues such as fracture spacing, frac volume, perforation distribution, proppant selection and wellbore length also affect well production and economics. A summary of completion and frac methodology for the Eagle Ford, in addition to a ranking of controllable (completion and frac design) and non-controllable (reservoir and geology) parameters that affect Eagle Ford production, will be included in this paper. The information contained in this paper will be useful to those interested in reservoir, completion and frac parameters that affect production from shales analogous to the Eagle Ford. Reservoir quality, completion and frac methodology effects on production results will be quantified in this paper.
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Visualizing Stress Trajectories around Pressurized Wellbores
Authors Ruud Weijermars and Dan Schultz-ElaA new approach, using stress functions, reveals how each component of the stress regime affects the stress pattern around the wellbore. The effect of tectonic far field stress on the stress trajectories in the host rock near a wellbore is visualized in a series of plots with the analytical stress trajectory solutions for a large range of net pressures on the wellbore. The deviatoric stresses around a wellbore result from the dynamic superposition of (1) far field tectonic stress, (2) near wellbore stress due to lithostatic pressure near the open hole, (3) pore over-pressure or under-pressure in the host rock, and (4) hydraulic pressure applied on the wellbore. The principal stress trajectory plots are used to determine the suitable options for well orientations and to delineate stress trajectory control of the incipient brittle failure patterns for hydrofracs and wellbore breakouts. Our approach provides fundamental insight, with an important practical application for improved understanding of the growth of hydrofractures.
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Water Management and Microbial Control Programs in the Exploitation of Unconventional Hydrocarbons
Worldwide, the production of natural gas and now oil from shale basins (source rock) has been embraced as a commercially viable way of producing unconventional energy resources leading to a revolution in gas production in the US. Developments to invest in and tap into this alternative way of gas production are taking off in Europe and Asia. Hydraulic fracturing is a proven technology, used for many years to develop hydrocarbon resources. Successful strategies with hydraulic fracturing include the safe and effective use of chemical additives, proper well casing and robust water management programs. During the exploitation of hydrocarbons from shales, chemical additives such as corrosion inhibitors, gelling agents, biocides etc, have to be used in the fracturing of wells. Sustainable chemistries and effective product stewardship programs are required to minimize environmental and human exposure hazards. The addition of water with organic molecules to the actual fractured wells makes these environments subject to unwanted growth of microorganisms and biofilm development, which has detrimental effects on hydrocarbon flow and leads to pipeline/equipment corrosion. Often the presence of sulfate reducing microorganisms leads to unwanted H2S production and subsequently souring. Due to this, water cycle management and properly designed microbial control programs for all water sources including injected water or produced water, are required. Because the microbial challenges and environmental parameters of these water sources vary, different microbial control strategies and treatments are required for each source. New formulations of biocides and control programs aimed at the needs of the gas and oil industry have been developed, e.g. improved heat stability and the reduction in biocide levels to achieve the same level of microbial control. These newly developed microbial control technologies will be presented in this paper, and the related regulatory and product stewardship support will be shortly addressed.
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Exploring Shale Basins using Existing Wells
Authors Jason Pitcher, Shan Kwong, Jeffrey Yarus and Mike MullenIn the search for unconventional shale plays with commercial potential, many operators have properties in petroprovince basins containing wells through potentially productive shale zones. These shales were often encountered as part of exploration or development programs for deeper conventional targets. Often, the overlying shale is known to have had gas or oil shows reported during initial drilling, but little or no additional geological data was acquired at the time. This paper discusses the workflow and method to use the minimal information from these existing wells, and to quantitatively incorporate them into a basin exploration program. The process begins with a single new well, such as a sidetrack from an existing well, which is evaluated with the full array of open hole logging tools. Coring (conventional or sidewall), DFIT tests, and other shale-specific logging tools are performed on this initial well. Pre-existing wells that penetrate the objective shale can also be quantitatively assessed for relevant shale properties by using specialized logging tools, such as a combined through-casing pulsed neutron and sonic tool, to map relevant shale properties. These tools are calibrated to the open hole data to generate a wider distribution of data points containing critical shale properties that can be demonstrated to have a strong relationship with production. After the data acquisition process has been performed, the data are combined with existing seismic and structural information to delineate the best areas for further evaluation. Using modern mapping tools, a basin can be rapidly appraised to identify sweet spots, providing further exploration targets for evaluation drilling. This paper discusses limitations, best practices, workflows, and methods, and includes an example of a European shale evaluation log to demonstrate this exploration technique.
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Geosteering in Unconventional Shales: Current Practice and Developing Methodologies
Authors Jason Pitcher and Tavia JacksonCurrent well placement in unconventional shale ranges from simple geometric well placement to a gamut of patternrecognition systems and geosteering with geochemical and geomechanical analyses. The wide diversity of systems used leads to uncertainty in the effectiveness of any strategy, with confusion as to the true value or merit of a particular technique. Often, a well-placement strategy is based on what came before, with little regard as to the complexities or differences between reservoirs. This paper reviews the current common practices used in geosteering in shales, for both gas- and oil-producing reservoirs. A brief history of strategy development is outlined, with comments about its perceived effectiveness and value. Examples of successes and failures are examined to attempt to determine the viability of a particular strategy. Finally, alternative approaches and methodologies are reviewed and examined, with comments about the potential application, benefits, and value.
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Microseismic Monitoring of Fracture Networks During Hydraulic Stimulation: Beyond Event Locations
Authors J-M. Kendall, J. P. Verdon, A. Baird, A. Wuestefeld and J. T. RutledgeThe successful exploitation of tight-gas reservoirs requires fracture networks, sometimes naturally occurring, often hydraulically stimulated. Borehole microseismic data acquired in such environments hold great promise for characterising such fractures or sweet spots. The loci of seismic events delineate active faults and reveal fracture development in response to stimulation. However, a great deal more can be extracted from these microseismic data. For example, inversions of shear-wave splitting data provide a robust means of mapping fracture densities and preferred orientations, useful information for drilling programs. They can also be used to track temporal variations in fracture compliances, which are indicative of fluid flow and enhanced permeability in response to stimulation. Furthermore, the frequency-dependent nature of shear-wave splitting is very sensitive to size of fractures and their fluidfill composition. Here we demonstrate the feasibility of using such analysis of shear-wave splitting measurements on data acquired during hydraulic stimulation of a tight-gas sandstone in the Cotton Valley field in Carthage, West Texas.
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Permeability Upscaling for Carbonates from the Pore-Scale Using Multi-Scale Xray-CT Images
Authors A.D. Khalili, C.H. Arns, J.-Y. Arns, F. Hussain, Y. Cinar, W.V. Pinczewski, S. Latham and J. Funkbility due to large permeability contrasts. The most accurate upscaling technique is employing Darcy’s law. A key part of the study is the establishment of porosity transforms between highresolution and low-resolution images to arrive at a calibrated porosity map to constraint permeability estimates for the whole core.
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Shale Plays in The Netherlands
Authors Sander Bouw and Jan LutgertThe Netherlands is a mature hydrocarbon province. EBN, the Dutch state participant for hydrocarbon exploitation and exploration, has identified shale plays as one of the contributors to add reserves and to maintain production at the current level. The main source rock for the limited amount of oil accumulations in The Netherlands are the Lower Jurassic (Toarcian) oil-prone shales. Lower Carboniferous (Namurian) hot shales have often been suggested as possible contributor to oil and gas Formation in The Netherlands as well, but this has not been proven to date. Recent discoveries of gas in the time-equivalent Bowland shales in the UK have encouraged interest in the production potential of these shales in North-western Europe. In this paper the geological and geomechanical properties of the Lower Jurassic and Lower Carboniferous are presented in a shale play context. The assessment methodology is subdivided in three sections: 1) the overall geology of the play, 2) the type and quantification of hydrocarbons present and 3) the production characteristics. New and specific measurements on core and cutting material include pyrolysis, methane adsorption, mineralogy, texture, porosity, permeability, static and dynamic geomechanical properties, hardness and fracture conductivity. The two identified plays show very distinctive properties. The Lower Jurassic samples indicate to be mostly thermally immature for dry gas implying that liquids can be expected. The Lower Carboniferous samples show areas that are overcooked. Mineralogical and geomechanical data suggest that different stimulation strategies may be necessary for these two plays to produce hydrocarbons effectively. The source rocks of Lower Jurassic age qualify as relatively soft while the Lower Carboniferous shales with high TOC content classify as very hard. Comparing the results of the assessment to known shale plays in the US, the plays position themselves in the opposite extremes of the productive shale play spectrum.
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After a Decade of Microseismic Monitoring: Can We Evaluate Stimulation Effectiveness and Design Better Stimulations
Authors Andreas Wuestefeld, Ted Urbancic, Adam Baig and Marc PrinceOver the past decade, microsesimic monitoring has become the approach most oftenused to gain an in-situ understanding of the rock's response during hydraulic fracture stimulations. From initial monitoring performed in the Barnett Shale to monitoring currently being carried out for example in the Horn River and Marcellus formations, we review the evolution of microseismic monitoring from the viewpoint of data collection (single versus multi-well array configurations, utilization of long lateral stimulation wells), to data analysis, to the incorporation of microseismic parameters to constrain and validate reservoir models. Generally, we have observed that overall fracture height, width and length, orientation, and growth vary from formation to formation and within each formation, thereby highlighting the ongoing necessity for microseismic monitoring. Additionally, through the use of advanced microseismic analysis techniques, such as Seismic Moment Tensor Inversion (SMTI), details on rupture mechanisms have been used to assess stimulation effectiveness, define complex Discrete Fracture Networks (DFN) and provide estimates of Enhanced Fluid Flow (EFF), which assist in calibrating and validating reservoir models. Utilizing spatial and temporal distributions in DFN and EFF, along with estimates of fracture interconnectivity and complexity, the role of pre-existing fractures and fault structures in the rock matrix can be established and used to provide more realistic estimates of stimulation parameters such as Stimulated Reservoir Volume (SRV).
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New Hydraulic Fracturing Process Enables Far-Field Diversion in Unconventional Reservoirs
Authors Fraser McNeil, Klaas van Gijtenbeek and Mark van DomelenThe challenge in recovering hydrocarbons from shale rock is its very low permeability, which requires cost-effective fracturestimulation treatments to make production economic. Technological advances and improved operational efficiency have made production from shale resources around the globe far more viable; however, while the wells being completed today are proving to be reasonably economical, the question that remains is if the operators are truly capitalizing on their full potential. In recent years, the industry has been in search of a better method to enable well operators to capitalize on the natural fractures commonly found in shale reservoirs. If properly developed, these natural fractures will create a network of connectivity within the reservoir, potentially improving long-term production when they have been propagated. In most shales, however, the stress anisotropy present can prevent sufficient dilation of the natural fractures during stimulation treatments. To induce branch fracturing, far-field diversion must be achieved inside the fracture to overcome the stresses in the rock holding the natural fractures closed. Increasing net pressure during the treatment will enhance dilation of these natural fractures, creating a complex network of connectivity, and the greater the net pressure within the hydraulic fracture, the more fracture complexity created. Most of the various processes introduced previously are limited because multiple perforated intervals or large open annular sections are treated at one time. Also, to achieve the high injection rates required, they are treated down the casing, so that any changes made to the treatment require an entire casing volume to be pumped before these changes reach the perforations. This paper presents a case history of a multistage-fracturing process that allows real-time changes to be made downhole in response to observed treating pressure. This functionality enables far-field reservoir diversion to be achieved, ultimately increasing stimulated reservoir contact (SRC).
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Shale Reservoir Properties from Digital Rock Physics
Authors Joel D. Walls, Elizabeth Diaz and Timothy CavanaughA majority of the whole core samples recovered in the US today come from shale reservoirs. A primary reason for so much shale coring is that shale well log analysis requires rigorous core calibration to provide reliable data for reservoir quality, hydrocarbon-in-place, and hydraulic fracturing potential. However, the uncertainty in interpreting shale well log data is sometimes matched or exceeded by the uncertainty observed in traditional methods of analyzing core samples. Most commercial core analysis methods in use today were developed originally for sandstones and carbonates exceeding 1 millidarcy in permeability. High quality, organic-rich shale on the other hand is usually lower than 0.001 millidarcy. This extremely low permeability creates substantial challenges for existing methods and has contributed to the rapid rise of a new approach to reservoir evaluation called Digital Rock Physics (DRP). DRP merges three key technologies that have evolved rapidly over the last decade. One is high resolution diagnostic imaging methods that permit detailed examination of the internal structure of rock samples over a wide range of scales. The second is advanced numerical methods for simulating complex physical phenomenon and the third is high speed, massively parallel computation using powerful graphical processing units (GPUs) that were originally developed for computer gaming and animation. Based on pore-scale images from a wide range of organic shales, it can be seen that organic material is present in a variety of forms. Three primary forms of organic matter are commonly observed; non-porous, spongy, and pendular. Non-porous organic components fill all of the available non-mineral space leaving virtually no porosity or fluid flow path. Porous or “spongy” organic material is commonly encountered in thermally mature gas shales. Pendular organic material appears to fill the small inter-granular and grain contact regions, leaving open pore space in the larger voids. These pore types are largely controlled by kerogen type and thermal maturity, and they exert large influence on the porosity, permeability, and overall shale reservoir quality.
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