- Home
- Conferences
- Conference Proceedings
- Conferences
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
74 results
-
-
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.
-
-
-
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.
-
-
-
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.
-
-
-
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.
-
-
-
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.
-
-
-
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.
-
-
-
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.
-
-
-
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.)
-
-
-
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.
-
-
-
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.
-
-
-
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.
-
-
-
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.
-
-
-
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.
-
-
-
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.
-
-
-
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.
-
-
-
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.
-
-
-
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.
-
-
-
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.
-
-
-
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.
-
-
-
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.
-
-
-
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.
-
-
-
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.
-
-
-
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.
-
-
-
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.
-
-
-
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.
-
-
-
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.
-
-
-
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.
-
-
-
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.
-
-
-
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.
-
-
-
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.
-
-
-
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.
-
-
-
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.
-
-
-
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.
-
-
-
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.
-
-
-
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.
-
-
-
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.
-
-
-
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.
-
-
-
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.
-
-
-
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.
-
-
-
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.
-
-
-
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.
-
-
-
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.
-
-
-
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.
-
-
-
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.
-
-
-
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.
-
-
-
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.
-
-
-
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.
-
-
-
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).
-
-
-
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).
-
-
-
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.
-
-
-
Impact of Geomechanics on Microseismicity
Authors Karn Agarwal, Michael J. Mayerhofer and Norman R. WarpinskiThe proper interpretation of microseismic event patterns to estimate hydraulic-fracture geometries is critical for understanding well performance in unconventional reservoirs. Besides factors such as microseismic event location uncertainty, advanced interpretations should also include a proper understanding of the geomechanical context in which these events take place and the underlying mechanisms that link the hydraulic fracture to the microseismic events. In this paper we investigate the different mechanisms that can cause microseismic activity around a hydraulic fracture from the viewpoint of a 3D elasto-static model to explain the behavior of microseismic event patterns. Stress perturbations caused by the opening of hydraulic fractures, opening of extensional branch fractures, and leakoff-related effects are considered. Multiple transverse fractures as well as dilated natural fractures orthogonal to the hydraulic-fracture direction are modeled under different sets of reservoir and treatment conditions to gain insight into the importance of different mechanisms. An important observation is that stress changes alone caused by tensile opening behind the hydraulic-fracture tip cannot cause microseismic events under any set of reservoir conditions normally encountered in practice. The results indicate that tip effects, propagation of extensional branch fractures, and activation of natural fractures upon intersection should be the main drivers of microseismic activity in shale-gas plays. The modeling shows that microseismic events are expected to occur very close to the hydraulically activated fractures or planes, thus enhancing the value of microseismic monitoring. The modeling also showed that under certain conditions (critically stressed formations), the shear zone caused by tip effects can extend fairly far ahead of the fracture tip, which needs to be considered in the interpretation of fracture geometry. The presented results help to constrain and enhance the interpretation of microseismic data, from a geomechanical perspective.
-
-
-
Improving Completion and Stimulation Effectiveness in Unconventional Reservoirs – Field Results in the Eagle Ford Shale of North America
Authors C. D. Pope, Terry Palisch and Pedro SaldungarayIn an unconventional reservoir, the success of a project is driven by the completion. Unconventional plays have become the primary area of development in the US, and shale formations dominate the current rig activity. Most shale wells are drilled utilizing long horizontal wellbores, and completed using cemented or uncemented casing strings. To be economic, they require large hydraulic fracture treatments in multiple stages along the lateral. Total well costs are driven by the cost of fracturing, often representing as much as 60% of the total well cost. This requires the operator to select the best completion method which includes casing and wellhead selection that is based on stimulation needs. The stimulation is regulated by injection rates, treating pressures, the volume of the stimulation, type of fluid, proppant selection, perforations, and the number of stages. This paper focuses on several areas that are critical in a successful completion such as: casing size and pressure rating, wellhead selection, treatment design, spacing of the perforations and stages, linear verses cross-linked fluid, and the impact of proppant selection. With over 1800 wells completed and stimulated so far, a comparison of successful treatments and the cause of unsuccessful treatments will be provided. A review of actual field applications will be presented where possible, and a method for identifying best completion practices will be discussed. Those working in or considering developments in unconventional plays around the world will be able to compare their current completion techniques to those presented in the paper. In addition, while no two resource plays are the same, the findings in this paper can be used by engineers as a guide for moving up the learning curve more quickly in other unconventional plays.
-
-
-
Can We Achieve Acceptable Fracture Conductivity Using WaterFracs?
More LessAfter 1970, the technology of hydraulic fracturing began to quickly accelerate, especially as to the industry focus on fracture conductivity. We saw a transformation in our frac fluids as we moved away from crudes and thin water gels to higher viscosity emulsion systems, foamed gels, and even crosslinked gel systems that could deliver significantly more proppant as we chased after better fracture conductivity. Using these more viscous gels we moved to “Massive Hydraulic Fracturing” of tight gas sand formations. This grew to multi-million pound proppant placements as the age of crosslinked gels began to dominate most of the fracture stimulation landscape as we tried to place very long, highly conductive fractures. However, the decade of the 1970’s also had Claude Cooke showing us that sand was a very limited proppant for deeper wells, and then later showing that gel residue could seriously reduce insitu fracture conductivities! (Cooke 1973; 1975; 1976; 1977) During the early 1980’s North America experienced the greatest rig activity ever, but then the mid-80’s gave us the greatest crash the oilfield had ever seen! Fortunately, this also resulted in our industry laboratories having the time to upgrade testing equipment and procedures to “realistic” test conditions for evaluation of packed proppant bed conductivity. This meant longer testing times, high temperatures, and with exposure to frac fluids. This research would subsequently launch the search for better gel breakers and lower residue gels (which continues today). Unexpectedly, in the 1990’s a few operators in tight sandstone applications in East Texas started re-inventing Slick Water fracs (WaterFracs), placing only 15-20% as much proppant as crosslink gel fracs, yet claiming equal or better overall economics. To add further consternation, George Mitchell found another application for WaterFracs and eventually showed the world that a hydrocarbon-source shale formation, the Barnett, can actually be a commercial producer itself. During the early 2000’s, the combination of long horizontals, and extreme multi-stage hydraulic fracturing (mostly using Waterfracs) turned the Barnett Shale into the launching pad of our present-day madhouse search for the next great shale play to chase. It is clear that long horizontal completions and WaterFrac stimulation methods have played an important role in opening the door to economic success in the numerous “resource plays” (i.e. shales). In this paper we will investigate if WaterFrac treatments are violating or upholding (?) one of our most significant fracturing beliefs: Fracture Conductivity should be optimized. Until we moved to the ultra-low formation permeabilities, we would generally say we should try to maximize our conductivity, but with WaterFracs designs it often seems we may instead be minimizing it, and this will be discussed here.
-
-
-
Probabilistic Reserves and Resources Estimation: A Methodology for Aggregating Probabilistic Petroleum Reserves and Resources
Authors M. Galvao, L. Hastenreiter, J. Molina, A. Quadros, J. Montechiari and S. HamacherThe oil industry strives to create an international standard for classification and estimation of resources since the 1930s. The goal is to provide investors with information obtained under the same assumptions, as to facilitate the comparison between petroleum companies. In 2007 the four major international organizations, Society of Petroleum Engineers (SPE), American Association of Petroleum Geologists (AAPG), World Petroleum Council (WPC) and Society of Petroleum Evaluation Engineers (SPEE), jointly released a single set of guidelines for classification and evaluation of oil and gas resources, the Petroleum Resources Management System (PRMS, 2007). Several methodologies for estimating reserves can be employed within the PRMS’s (2007) premises, which can be classified as deterministic or probabilistic. Unconventional resources emerge as a new frontier for the oil industry, thus implying high uncertainty levels in both technical and economic assessments. The main purpose of this paper is to explore this issue and to propose a correlation-based probabilistic methodology for aggregating oil and gas reserves of conventional and unconventional resources. The methodology is in accordance with the guidelines of the PRMS (2007) and with the new rules of the Securities Exchange Commission 2009 (SEC). The correlation assessment evaluates technical and operational features, and the probabilistic aggregation is performed by Monte Carlo Simulation (MCS). Besides the introductory section, this paper comprises four other sections. A literature review presents definitions of conventional and unconventional resources, and an examination of classification, estimation and aggregation of reserves, important for better understanding the following sections. The third section describes the proposed correlation-based probabilistic methodology. Afterward, a case study presents an application of the methodology. Finally, the last section synthesizes the main conclusions.
-
-
-
Novel Water Based Mud for Shale Gas, Part II: Mud Formulations and Performance
Shale-gas plays and other unconventional resources have gained significant importance worldwide. Historically, synthetic based drilling fluids (SBM) are used in these plays when no environmental concerns are in place and are preferred when wellbore stability is necessary. In this paper, we study the use of an improved water based drilling fluid (WBM) that is simple in formulation and maintenance that shows excellent rheological properties, maintains wellbore stability, and a good environmental profile. A combination of well-known and economically affordable materials is combined with new technology to achieve desired rheological properties and wellbore stability. The use of nanoparticles to decrease shale permeability by physically plugging nanoscale pores holds the potential to remove a major hurdle in confidently applying water-based drilling fluids in shale formations, adding a new advantage to the studied fluid. Silica nanomaterials were investigated for this purpose. Due to their commercial availability, these materials can be engineered to meet the specifications of the formation. Characterization of the nanoparticles was completed with Transmission Electron Microscopy (TEM), dynamic light scattering, and X-ray-photoelectron spectroscopy. Rheological properties and fluid loss are studied together with other important properties such as shale stability and anti-accretion properties. The authors will describe new laboratory methods used to investigate these properties, from a modified API fluid loss test to the Shale Membrane Test that measures both fluid loss and plugging effects and illustrate additional future research that includes adding reactive species, and anchoring them to the pores, thus stabilizing the shale further.
-
-
-
Real-Time Downhole Monitoring of Hydraulic Fracturing Treatments Using Fibre Optic Distributed Temperature and Acoustic Sensing
Authors Mathieu M. Molenaar, Erkan Fidan and David J. HillIn order to make commercial and development decisions effectively and more rapidly, new appraisal and testing technologies are needed to maximize early data collection and subsequent subsurface understanding as quickly as possible. For Unconventional Gas and Light Tight Oil (UGLTO) projects, some of this critical data can be derived from hydraulic fracture stimulation and inflow profiling activities. For UGLTO projects, achieving an optimum hydraulic fracture stimulation is a continuous endeavor beginning as early as possible; and balancing the cost of completion vs. production performance is critical as the completion/stimulation is a large cost component of the well and heavily influences production rate/ultimate recovery. The fast paced development and introduction of new completion technologies requires diagnostic technology that can help us understand stimulation effectiveness, assess new completion technologies, and evaluate which zones are the most productive. One emerging technology, fibre optic distributed sensing has the potential of providing key insights during both the hydraulic fracturing and initial flowback. The passive nature of fibre optic sensors allows intervention-free surveillance, which makes fibre-optic technology an effective platform for permanent sensing in producing wells. Until recently, the oil & gas industry fibre optic sensing technology has focused mainly on temperature (DTS) profiling along the wellbore. In 2009, it was first demonstrated how fibre optic distributed acoustic sensing (DAS) can also be used for downhole applications. Where hydraulic fracture diagnostics based on DTS alone in the past sometimes yielded ambiguous results, the combination of both acoustic and temperature sensing provides a step-change improvement in the ability to perform real-time and post-job diagnostics & analyses of the stimulation. The different horizontal well case studies presented in this paper will illustrate how the combination of DTS and DAS has the potential to enhance the monitoring, assessment, and optimization of openhole and limited entry designed hydraulic fracture stimulation treatments.
-
-
-
3D Seismic as an Aid to Design Syngas Production by Means of Underground Coal Gasification (UCG) Methodology
Authors Dries du Plooy, Béla Szanyi, Jenő Mázik, Péter Majoros, Tamás Tóth, Zoltán Kádi and Balázs KoroknaiThe unconventional use of coal to supplement Natural Gas (NG) in the power and chemical industry makes Underground Coal Gasification (UCG) an important technology in economically producing unconventional gas. Present day exploration and production technologies pave the way “from a potential to actual production”. A 3D seismic survey has been applied in Southern Hungary for the site selection of UCG resource blocks, as well as in the design of the most optimal exploration drilling program. The latter exploration techniques directional drilled injection and production wells are planned in the coal seams to sustain the burning front. Wildhorse UCG Kft is a pioneer in the design and introduction of the environmentally friendly coal based syngas for electric power generation in East-Central European countries. Additionally the Copyright 2012, Society of Petroleum Engineers This paper was prepared for presentation at the SPE/EAGE European Unconventional Resources Conference and Exhibition held in Vienna, Austria, 20-22 March 2012. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright. syngas can be utilised to supplement national gas supplies as alternative fuel gas. In this presentation the role of 3D seismic is discussed in defining the “Mecseknádasd UCG project”. Wildhorse UCG Kft completed 3D seismic measurements in April and May of 2011 in the Mecseknádasd UCG project area. The goal of the seismic measurements is to image and clarify the structural conditions and to reveal faults and other discontinuities in the coal formation explored previously by historic deep drilling in the area. The processing and interpretation of the survey results have been performed together by GEOMEGA Kft and Wildhorse UCG Kft and the presentation covers the complete survey results of the Mecseknádasd UCG exploration project: − Newly processed results of historical boreholes − Results of the seismic survey − Geological and geophysical results of new boreholes − Possibilities for upgrading the geological model with integrated interpretation by using the available geophysical data (seismic, new boreholes, historic boreholes) − The possibilities for the application of 3D seismic survey in the design process of the UCG technology and to monitor the UCG engineering process
-
-
-
Unconventional Reservoirs: Basic Petrophysical Concepts for Shale Gas
Authors Juan C. Glorioso and Aquiles RattiaUnconventional reservoirs have burst with considerable force in oil and gas production worldwide. Shale Gas is one of them, with intense activity taking place in regions like North America. To achieve commercial production, these reservoirs should be stimulated through massive hydraulic fracturing and, frequently, through horizontal wells as a mean to enhance productivity. In sedimentary terms, shales are fine-grained clastics rocks formed by consolidation of silts and clays. In log interpretation of conventional reservoirs, it is very common to observe that the clay parameters used to correct porosity and resistivity logs for clay effects are in fact read in shaly intervals rather than in pure clay. Although no considerable deviation have been observed in shaly sandstones, anyway these concepts and procedures must be reviewed to run log analysis in shale gas. Organic matter deposited with shales containing kerogen that matured as a result of overburden pressure and temperature, giving rise to source rocks that have yielded and expulsed hydrocarbons. Shale gas reservoir type is a source rock that has retained a portion of the hydrocarbon yielded during its geological history so that to evaluate the current hydrocarbon storage and production potential it is necessary to know the kerogen type and the level of TOC - total organic carbon - in the rock. Produced gas comes from both adsorbed gas in the organic matter and "free" gas trapped in the pores of the organic matter and in the inorganic portions of the matrix, i.e. quartz, calcite, dolomite. In these unconventional reservoirs, gas volumes are estimated through a combination of geochemical analysis and log interpretation techniques. TOC, desorbed total gas content, adsorption isotherms, and kerogen maturity among other things can be measured in cores, sidewall samples and cuttings, in the laboratory. These data are used to estimate total desorbed gas content and adsorbed gas content which is part of the total gas. Also in laboratory, porosity, grain density, water saturation, permeability, mineral composition and elastic modules of the rock are measured. Laboratory measurement uncertainty is high and consistency between different providers appears to be low, with serious suspicions that procedures followed by different laboratories are the source of such differences. The permeability is one of the most important parameters, but at the same time, one of the most difficult to measure reliably in a shale gas. Core calibrated porosity, mineral composition, water saturation and elastic modules can be obtained through electric and radioactive logs. All these information is used to estimate log derived total gas volume which results are also subject to a high degree of uncertainty that must be overcome. Once this key information is obtained, it is possible to estimate different gas in-situ volumes. Indeed, an estimate of porosity-resistivity based total gas in-situ and, on the other hand, geochemical based adsorbed gas in-situ can be performed. Log total gas in-situ can be, and it is advisable to do, compared with adsorbed gas estimations and also with another gas measurement called direct method - total gas desorption performed on formation samples. The difference between log total gas in-situ and adsorbed gas in situ should be the "free" gas in situ. Free gas occupies the pores of kerogen and matrix; also it can be stored in open natural fractures if such fractures are present. The main objective of this paper is to discuss the state-of-the-art in petrophysical evaluation of shale gas reservoirs, to summarize the experiences of operators and researchers, and to bring some views on the criteria and techniques for the evaluation of cores and logs. An inventory of laboratory tests and results, log responses in the presence of kerogen, log interpretation techniques and estimation methods for different volumes of gas in-situ, together with important aspects of the use of analogy in shale gas reservoirs has been done. At the end, a basic petrophysical workflow is outlined for the volumetric determination of gas in situ.
-
-
-
Experimental Measurements of Mechanical Parameters of Class G Cement
Authors Catalin Teodoriu, Zhaoguang Yuan, Jerome Schubert and Mahmood AmaniThe new quest of unconventional resources is the achievement of well integrity which is highlighted by the inadequacy of conventional cementing procedures to provide zonal isolation. High temperatures and pressures or even post-cementing stresses imposed on the cement sheath as a result of casing pressure testing and formation integrity tests set in motion events which could compromise the long term integrity of the cement sheath due to fatigue. Knowledge of the mechanism of fatigue in cement and factors that affect it such as the magnitude of the load, strength and composition of the cement, mechanical properties of the cement and pattern of load cycles are important to achieve a realistic design of a cement system that will be subjected to fatigue loading. Such a design will go a long way to ensure the long term integrity of a well operating under downhole conditions. Finite element investigations help engineers to assess the stress magnitude and evolution for a given well configuration, but when structural calculations for casing-cement system are required, missing input parameters reduce the quality of the results. In order to have reliable data we performed an extensive experimental work using Class G cement in order to measure the principal parameters for mechanical structural calculations: compressive and tensile strength, Young modulus, Poison Ratio. The data was measured under room conditions and elevated temperature and pressure. The results were also extrapolated for a time period for more than 300 days. The paper will provide an excellent data inventory for class G cement that can be used when mechanical studies on cement, like finite element studies, are required.
-
-
-
Study of Class G Cement Fatigue using Experimental Investigations
Authors Christian Kosinowski and Catalin TeodoriuThis paper presents the results of laboratory investigation about fatigue of Class G wellbore cement exposed to radial loads under room temperature conditions. While fatigue is well described for metals, wellbore cement fatigue is a rather unknown field. As well cements can be exposed to cyclic loading situations like in new oilfield technologies e.g. enhanced oil recovery by steam injection or geothermal applications using single-well-solutions, cement damage by fatigue becomes a more important issue. Cement integrity is crucial environmental and economic issue and no risk on cement failure should be accepted. The thermal induced loads in the reality were replaced by mechanical loads that recreates the stress situation on the cement. In order to evaluate the behavior of the cement, experiments were performed to investigate how cement reacts to cyclic loadings. A low number of cycles mean up to 100 loadings sequences. Samples of a pipe-cement-compound recreating the wellbore geometry are tested in a hydraulic press under axial loads. The stress situation in the cement sheath of the tested samples was calculated using a combination of numerical and analytical methods. Failure criteria were used to evaluate these calculations and could be used to predict future failure behavior. It has been found that fatigue of cement is rather similar for metal and cement at least in the low cycle range. For metals there is a specific stress limit where failure or significant damage to the material occurs within several cycles. This means, if the limit is exceeded the material will fail, maybe not at the first cycle, but it will fail over the cycles. Cement shows that this behavior is similar to metals, no other fatigue mechanisms like damage accumulation were observed, just a straight load limit.
-
-
-
Non-Conventional Plays in Romania: the Experience of OMV Petrom
Authors Csaba KREZSEK, Simon LANGE, Radu OLARU, Cristina UNGUREANU, Pervin NAMAZ, Roxana DUDUS and Valentin TURIThis paper describes the key findings of a regional study that targeted the unconventional potential of exploration assets hold by OMV Petrom in Romania. Three unconventional plays have been evaluated, including the (1) Silurian and (2) the Dogger on the East European Margin (including Moesia), and the (3) Oligocene in Maramures (Pienides). The Silurian shales are at 2- 4 km depth in the gas window on Western-Central Moesia. Maturity in most cases has been reached by the Late Paleozoic and it was followed by significant exhumation during the Hercynian Orogeny. The quality of Silurian shale represents a major uncertainty, due to the sparse dataset represented by old wells. The Dogger shales of Northern Moesia are in the oil and gas window under the most external thrusts of the Carpathians at depths that exceed 4 km. The shales have TOC values up to 6 %. Oligocene shales with TOC of up to 10 % in Maramures are in the oil window at depths of less than 2 km. This makes them a very attractive target for shale-oil exploration. However, major setbacks are the complex tectonic structure, rugged topography and large-scale exhumation. Ongoing exploration efforts for non-conventional plays are targeted to define the mechanical properties and the exploration sweet spots in the above mentioned plays, but also assessing the potential of the Late Paleozoic bituminous dolomites of Moesia and other black shales in the Carpathians.
-
-
-
Validation of Surface and Shallow Microseismic Array for Deep Reservoir Monitoring
Authors Anca Rosca and Christophe MaisonsMonitoring reservoir stimulation operations provides data for predicting production performance and for reservoir characterization but also, potentially, for compliance with local regulations. With improved drilling and completion technology the depth of the unconventional reservoirs produced increases and the options for deploying cost–effective microseismic monitoring equipment become limited. The monitoring technology has to adapt by optimizing acquisition geometry and data processing as well as the procedures that demonstrate the validity of the results. A practical solution for microseismic monitoring of stimulation operations in an unconventional reservoir under development is a surface or shallow distributed array. We are analyzing three such datasets together with complementary deep borehole sensor datasets to understand how to predict and validate the expected performance of distributed surface and shallow arrays. The surface recorded data is processed by stacking and event detection and location are accepted based on statistical criteria. This catalog of events is compared to the one obtained from borehole array where waveforms can be analyzed individually in order to validate the quality of event analysis.
-
-
-
Identifying Fault Activation in Unconventional Reservoirs in Real Time Using Microseismic Monitoring
Authors Michael Kratz, Andrew Hill and Scott WesselsIdentification of fault related microseismicity in hydraulic fracture treatments is crucial to understanding how treatments are stimulating a reservoir. Evaluating b values in combination with event source mechanism provides a reliable and intuitive method for separating fault related microseismic events from standard fracture related events. Typically this analysis is conducted after a treatment is complete and serves as a diagnostic tool to provide possible explanations for reduced production or designing future treatments on nearby wells to avoid an identified fault feature. Being able to identify such features in real time allows the operator to not only identify faults but to stop treatment and avoid these features all together saving time and materials that would otherwise be pumped into an area that doesn’t contribute to the overall stimulation of the reservoir, and could reduce production on the well. When evaluating b-values in real time, a technique that can identify faulting early in the initiation of fault stimulation is crucial for preserving the most resources during treatment.
-
-
-
Reserves and Performance Comparisons of Multi-Fractured Spearfish Horizontal Wells, to Various Fracturing Techniques and Well Spacing Configurations
More LessThe light oil bearing, low permeability, Spearfish formation, in Southwest Manitoba, Canada, has been a recent target of extensive horizontal drilling and fracture stimulation. An extensive completion database, along with historical production data, is available in the public domain. It is beneficial to review what the production trends illustrate about this play, in order to optimize the development of other similar types of low permeability sandstone plays, with regards to horizontal well spacing and fracture design. Decline analysis was performed on over 120 horizontal wells that had sufficient completion information available, to study the effects of varying fracture spacing and size. The emphasis was to review the longer term production histories of the oil wells, as well as the predicted ultimate reserves, and see if there were any discernible trends, when production was compared to various fracture parameters. Both the initial production rates and the ultimate reserves, showed significant data scatter when compared with fracture size, and number of fractures per well. It was difficult to make strong conclusions about initial production rates, being a function of varying fracture parameters. Closer analysis of individual wells, suggests that ultimate reserves appears related to the moveable oil-in-place, within the drainage area that a horizontal well produces from. It appears that well spacing effects and localized reservoir properties, must be taken into consideration, when analyzing the long-term performance of multi-fractured horizontal wells. It seems that caution is required, when drawing long-term conclusions from initial production results. The basic reservoir engineering principle of an oil well draining a defined reservoir volume, are still applicable to low permeability reservoirs. There appears to be a finite number of horizontal wells that can be drilled in any given area, and an optimum number of fracture stimulations that can be placed per well.
-
-
-
Lessons Learned from North America and Current Status of Unconventional Gas Exploration and Exploitation in China
Authors Ping Wang, Ruizhong Jiang and Shichao WangUnconventional gas has been paid more and more attention since the successful exploration in North America, China is no exception. Effective exploitation of unconventional gas can guarantee energy security, optimize energy structure and help protect environment in China. Successful experiences from North America are summarized, current status of unconventional gas in China is analyzed from three aspects: resources, technologies, polices. The success of North America profits from five reasons: governmental positive policies and tax preferences, advanced technologies, adequate pipeline infrastructure, small firms leading system, large demand of natural gas. China has large potential resources of unconventional gas. As to tight gas, the prospective resources of tight gas exceed 12 trillion cubic meters. For coal-bed methane(CBM), China is ranked 3rd after Russia and Canada and has 36.8 trillion cubic meters. China has just started shale gas study and has no definite evaluation. Until now, China has developed a series of technologies. For tight gas: high-precision 2D seismic, fast drilling, slim hole drilling. As for CBM: AVO response detect, penniform multi-lateral drilling and ultra-short radius jetting drilling. China has set many beneficial policies for unconventional gas especially for CBM, now the government is working hard on making positive policies and tax preferences for shale gas. There are several differences between North America and China: geological difference, land ownership, regulatory framework, pipeline network, small firms in America and national oil companies in China. Some suggestions are proposed for China: set positive policies and tax preferences, develop advanced and adaptive technologies, consummate natural gas market system and infrastructure, cooperate with foreign companies and monitor the effect of unconventional gas exploitation on environment. These summaries and suggestions can be instructive for other countries to develop unconventional gas.
-
-
-
Production Data Analysis in Eagle Ford Shale Gas Reservoir
Authors Bingxiang Xu, Manouchehr Haghighi and Dennis Cookeve analysis technology to analyse the production behaviour and to estimate the essential parameters for this reservoir. This type curve was constructed based on transient production rate with constant well pressure in a closed boundary of stimulated reservoir volume (SRV) with double porosity approach. In order to analyse the early production data we used Bello’s and Nobakht’s approach to account for apparent skin. In this study, three flow regimes were identified consisting of 1- bilinear flow; 2- matrix linear flow; and 3- boundary dominated flow. For the analysis of early flow regime, two possibilities of transition flow and apparent skin have been considered. First, the fracture permeability was estimated to be around 820 nano Darcy based on transition flow analysis. Second, the matrix permeability was estimated to be either 181 or 255 nano Darcy based on two different approaches in matrix linear flow regime. Furthermore, original gas in place (OGIP) and SRV were estimated from the boundary dominated flow regime. To validate the estimated matrix permeability, a single porosity numerical model with high permeability transverse fractures was built to match the production history. The permeability from simulation was in a good agreement with type curve analysis. Production forecasting has also been carried out using different adsorption isotherms. The results showed that the effect of desorption depends on the reservoir pressure and the shape of adsorption isotherm curve. In early time of production, desorption is usually not effective, however, for long-term production forecasting, it is necessary to account for this phenomenon by providing an accurate isotherm
-
-
-
Cyclic Shut-in Eliminates Liquid-Loading in Gas Wells
Authors Curtis Hays Whitson, Silvya Dewi Rahmawati and Aleksander JuellThis paper presents a method to eliminate production loss due to liquid-loading in tight gas wells. Cyclic shut-in control is a simple production strategy that particularly benefits lower-permeability stimulated wells, including but not limited to shale gas wells. Comparison is made between a gas well producing (1) in a “ideal” situation where 100% of liquids entering from the reservoir or condensing in the tubing are continuously removed (without shut-ins), (2) in a meta-stable liquid-loading condition with low gas rate, typical of most wells today, and (3) by the proposed strategy of cyclic shut-in control. We show that cyclic shutin control of stimulated low-permeability vertical wells to ultra-low-permeability horizontal multi-fraced wells can produce without ever experiencing liquid loading, and with little-to-no delay of ultimate recovery. Cyclic shut-in control can be applied to all stimulated, lower-permeability gas wells, from the onset of gas rates that result in liquid-loading. The strategy can also be used for wells which already have experienced a period of liquid-loading , but the expected performance improvement may be less because of near-well formation damage caused by historic liquid-loading – e.g. fresh-water backflow and liquid-bank accumulation. In historically liquid-loading wells, an initial period of liquid removal and/or light stimulation may be needed prior to initiating cyclic shut-in control. We show that the shut-in period should optimally be as short as operationally possible. Cyclic shut-in control is shown to work equally well for layered no-crossflow systems with significant differential depletion at the onset of liquid loading. Minimizing rate and recovery loss of liquid-loading gas wells is of international interest. We believe that cyclic shut-in control will become an industry standard practice for shale gas wells, and should lead to a significant ultimate increase in worldwide gas reserves. The method is extremely simple and requires only a rate-controlled wellhead shut-in device.
-
-
-
Selection Criteria for Tubular Connection used for Shale and Tight Gas Applications
Authors Catalin Teodoriu and Tu ClausthalAn unconventional reservoir poses not only difficulties in producing it economically but also requires constrains about the well construction and tubular selection in order to keep the budget in acceptable limits. The tubular used for well construction and well completion must offer maximum integrity at, if possible, minimum costs for the life of the well. The costs associated with tubular are generated by the steel price plus the connection costs. Use of premium connections may not be justified in all unconventional reservoir applications, but as this study will prove, they offer better solutions when the life if the well is considered. This paper starts with a review of main tight gas fields worldwide and based on the well analysis a general tendency for well completion will be shown. The second part of the work will focus in analyzing casing design criteria used in afore mentioned fields. As a result a comprehensive discussion about casing and coupling selection for unconventional wells will be generated. Premium versus non premium connections will be discussed and their impact on the life of the well will be analyzed.
-
-
-
Identification, Integration and Upscaling of Mudrock Types - A Pathway to Unlocking Shale Plays
Authors Joan M. Spaw and Marathon Oil CompanyA multidisciplinary approach to shale characterization in a variety of North American gas- and liquids-rich shale plays has lead to improved understanding of the bulk physical, chemical and mechanical properties of these deposits and their geologic history. This effort is leading to successful exploitation of these enigmatic resources. Microfacies analysis of mudrocks provides a platform for upscaling from the “nano” to the regional scale, and results in comprehensive mudrock characterizations. Microfacies analysis of mudrock types within a select stratigraphic interval in a basin leads to the recognition of mudrock lithofacies. Lithofacies identification allows for calibration of petrophysical models, documentation of basinspecific variations in mudrock composition and microfabrics, the distribution of organic-rich members of these intervals, definition of the mechanical stratigraphy for completion design, and provides the litho-stratigraphic building blocks for predictive sequence stratigraphic models. Successful exploration and exploitation of mudrocks as resources can be advanced when the recognition of mudrock lithofacies provides a methodical means to tie together the geologic, chronostratigraphic, geochemical and petrophysical data from a diverse spectrum of physical scales and technical disciplines.
-
-
-
Just-In-Time Perforating for Controlled, Cost-Effective Stimulation and Production Uplift of Unconventional Reservoirs
Authors Renzo Angeles, Randy Tolman, Wadood El-Rabaa, Shalawn Jackson and Kris NygaardRecent advances in multi-stage stimulation technologies, including open- and cased-hole types, have largely overlooked the advantages of single-zone stimulation due to hardware and cost limitations. In most conventional methods, multiple perf clusters are treated at once using one single frac stage with the expectation that equally-stimulated fractures will be created at each perf cluster within tens and hundreds of feet. This creates over-stimulation in some perf clusters and under-stimulation in others, which unveils the current economic and practical limits of effectively creating fractures where needed, not where it is possible to place them. Other methods use a large number of frac plugs which require additional wireline trips and later need to be drilled out, increasing the total cost and mechanical risk of the completion. As lateral length increases, many operators also face the challenge of not being able to remove all frac plugs due to coiled-tubing depth limitations. This paper introduces the recent implementation of Just-In-Time Perforating (JITP) in shale gas, unconventional plays. JITP is one of the Multi-Zone Stimulation Technologies (MZST) developed and patented by ExxonMobil over a decade ago and extensively used in vertical and S-shaped wells in the Piceance basin, Colorado, and recently implemented in the XTO Fayetteville Shale, Arkansas. JITP creates multiple single-zone fracture stimulations on a single wireline run using ball-sealer diversion and perforating guns that remain downhole during fracturing. Other key features of this method are the use of less horse power, significant reduction in the number of frac plugs, fewer wireline runs, and added flexibility in water management. This paper describes the technical advantages and business justification for applying JITP in unconventional resources and also provides preliminary results from the performance of the JITP field trials in horizontal wells.
-
-
-
Assessment of SAGD Well Configuration Optimization in Lloydminster Heavy Oil Reserve
Authors M. Tavallali, B. Maini, T. Harding and B. BusahminLarge quantity of heavy oil resources are present in variety of complex thin reservoirs in Lloydminster area which are situated in east-central Alberta and west-central Saskatchewan. Primary depletion and waterflooding are the principal recovery techniques. Although these techniques work, the recovery factors remain low and large volumes of oil are left unrecovered when these methods have been exhausted. Because of the large quantities of sand production, many of these reservoirs end up with a network of wormholes that makes most of the displacement type enhanced oil recovery techniques inapplicable. Because of these high conductivity channels, only gravity drainage based techniques have a good chance of success. Among the applicable methods in Lloydminster area, SAGD has not received adequate attention, mostly due to the notion that heat loss in thin reservoirs would make the process uneconomical. While this may be true, the limiting reservoir thickness for SAGD under varying conditions has not been established. These reservoirs contain light oil with sufficient mobility. Therefore the communication between the SAGD well pairs is no longer a hurdle. This opens up the possibility of increasing the distance between the two wells and introducing elements of steamflooding into the process in order to compensate for the small thickness of the reservoir. The main objective of this study was to evaluate the effect of well configuration on SAGD performance and develop a methodology for enhancement of the SAGD performance through optimizing the well configurations for Lloydminster type of reservoir. A new well configuration was able to significantly improve the application of SAGD in thin reservoirs of Lloydminster. It provided high RF at reasonable cSOR. The effects of some common Lloydminster reservoir characteristics, which are problematic for the SAGD process (such as initial gas saturation, bottom water, and gas-cap) were investigated for the most promising well configuration
-
-
-
An Environmental Solution to Help Reduce Freshwater Demands and Minimize Chemical Use
Authors Jason E. Bryant and Johanna HaggstromNew technologies to reduce chemical exposure to personnel and the environment during fracturing operations are at the forefront of research and development efforts. Unconventional reservoir developments require large amounts of fresh water, sometimes up to 5 million gal to complete a well, leading to difficulty in water sourcing in remote locations or regions where droughts are persistent. Several new areas currently under consideration for shale exploration are in environmentally sensitive locations, making the water sourcing for fracturing operations even more critical. Freshwater use needs to be minimized, and a careful examination of current practices should be undertaken to reduce, eliminate, and recycle chemicals wherever possible. Furthermore, fracturing fluids essential for successful stimulation treatment should be comprised of chemicals adhering to environmentally acceptable standards. Recent developments have allowed one operator to minimize freshwater usage through recycling of their flowback and produced water using electrocoagulation (EC) technology. EC is a water-treatment process that removes colloidal solids through methods of coagulation, electroflotation, and settling. Unlike conventional water-treatment practices, such as reverse osmosis or distillation, EC generates relatively small quantities of waste, while leaving dissolved solids in the water. To ensure enough water was available for fracturing stimulation treatment, fresh make-up water was also used. This freshwater source was treated for bacteria using an ultraviolet (UV) trailer, which minimized the need for biocide on location. In addition, dry-blending technology was used to hydrate the gel without the aid of mineral oils. All of these processes were used to reduce the environmental impact on location. With increasing public scrutiny and concern over the practice of hydraulic fracturing in environmentally sensitive locations, fluid systems need to follow strict environmental guidelines. A new fluid system was developed with components from the US Code of Federal Regulations Title 21 (CFR 21), or the Generally Recognized as Safe (GRAS) affirmation process. While setting a high precedence by adhering to this environmental benchmark, the fluid performance was not compromised.
-
-
-
European Shale Gas, Getting Buy-in From the Public and Stakeholders
Authors Mark A. Miller and Eric VaughanDuring the past 10 years shale gas development projects have proven to be highly successful in a number of North American basins, and have become a game changer for the energy supply there. Because of these successes, shale gas exploration and development technologies are being deployed around the globe, including Europe. But while there appears to be vast shale gas resources across Europe, many industry analysts express concerns about the probability of repeating the North American successes in Europe. These concerns are based on the denser population in Europe, different safety and environmental regulations, and the doubts of many European residents about the overall safety of shale gas development. Moreover, unlike North America where landowners often are entitled to significant lease payments and royalties for their mineral rights, the mineral rights throughout most of Europe are owned by the governments, rather than the landowners. The combination of these factors adds to the difficulty of building public support for a shale gas program. This paper provides a discussion of a shale gas exploration program currently being conducted by Cuadrilla Resources in England. It examines the concerns of the local residents, and how these have affected media coverage, and support (or opposition) from politicians. It discusses the strategy and approach used by Cuadrilla for addressing questions and concerns from the local residents, various UK regulatory bodies, politicians and the media. While this paper focuses on a UK shale gas case, the conclusions and recommendations are applicable to any shale gas program in Europe or elsewhere.
-
-
-
Water Management – An Increasing Trend in the Oil and Gas Industry
Authors Freeman Hill, Steve Monroe and Reshmy MohananWater plays an essential role in the recovery of oil and gas. Managing subsurface water conformance can maximize hydrocarbon production and reduce operating costs. However, unchecked water can decrease hydrocarbon production, reduce oil and gas recovery, increase costs substantially, and lead to possible well abandonment. In the life of a well it is natural that water will eventually enter into the production stream. It is important to identify the water’s source and reason for the intrusion, and how it is interacting with the wellbore. This knowledge can be used to create an integrated customized solution that fits the needs of the well. An indepth understanding of the reservoir can avoid water problem areas in new infield drilling by the use of advanced navigation and directional systems. Water management is essential to maximizing returns on investment and in controlling costs. There are a variety of technologies available for near-wellbore control and reservoir water conformance. Understanding of the water mechanism followed by proper application is key to reducing excess water production.
-