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Wuestefeld, P. (RWTH Aachen University) | Hilgers, C. (RWTH Aachen University) | Koehrer, B. (Wintershall Holding GmbH Germany) | Hoehne, M. (RWTH Aachen University) | Steindorf, P. (RWTH Aachen University) | Schurk, K. (RWTH Aachen University) | Becker, S. (RWTH Aachen University) | Bertier, P. (RWTH Aachen University)
Upper Carboniferous sandstones in NW-Germany consist of thick successions of cyclothems and are major tight gas reservoirs. This study presents the heterogeneity exposed in a large quarry near Osnabrueck, Germany, which contains faulted and jointed third-order coarse- to fine-grained tight sandstone cycles separated by anthracite coal seams. First, we characterize the rocks and the lateral variation of rock properties such as porosity, diagenesis and structural inventory. Than we test whether the quarry may act as a reservoir analog to better constrain input data for reservoir modelling.
The tight sandstones are intensely compacted and cemented with quartz and generally characterized by low matrix porosities < 8 % (He-pycnometry on plugs and cuttings) and very low permeabilities (<0.01 mD). Porosity is generally secondary, formed by detrital and authigenic carbonate dissolution and dissolution of feldspars. Matrix porosity significantly increases up to 25% in corridors around faults. Rock types can be distinguished by spectral gamma ray in the quarry. Fluid flow within and around faults is indicated by quartz veins and fault mineralizations. Normal faults show and bands of clay smear and gouge, forming compartments. Fractures were analyzed in a 50 x 50 m section of the quarry wall using Lidar laser scanning. This digitized quarry face also allows the characterization of the lithology and quantitative measurement of bedding, fracture and fault orientation data in inaccessible areas.
Our high resolution field analog enables a better understanding of unconventional reservoir properties and reservoir quality at a subseismic scale, considering both the change of porosity during diagenesis and the formation of structures. Results may be used to develop data-driven exploration strategies and improved development options for similar subsurface tight gas reservoirs.
Tongyi, Zhang (Research Inst. Petr. Expl/Dev) | Wei, Pang (Sinopec Research Institute of Petroleum Engineering) | Juan, Du (Sinopec Research Institute of Petroleum Engineering) | Jun, Mao (Sinopec Research Institute of Petroleum Engineering) | Ying, He (Sinopec Research Institute of Petroleum Engineering) | Qiong, Wu (Sinopec Research Institute of Petroleum Engineering) | Xiaoxu, Feng (Sinopec Research Institute of Petroleum Engineering) | Panglu, Jiang (Sinopec Research Institute of Petroleum Engineering) | Dejia, Di (Sinopec Research Institute of Petroleum Engineering)
Designing hydraulic fracture stimulation to optimize well productivity requires knowledge of the initial reservoir pressure and permeability, the closure stress magnitudes in the reservoir and in bounding formations, a carrier fluid with a suitable leakoff coefficient, and rock properties such as the Young’s modulus and the Poisson ratio. When key parameters are left unknown, the hydraulic fracture stimulation is likely to be severely suboptimal.
This study integrates pressure buildup and production transient
analyses with microseismic surveys and the recorded pumping schedule to estimate the above-mentioned parameters in previously fractured wells on production for up to 7 years from a tight gas reservoir.
The first well completed in the block included a pressure buildup test that enabled accurate estimation of the initial reservoir pressure and permeability. A post-fracture buildup test was also conducted, and annual pressure buildup tests in 6 subsequent years showed continuous changes in the fracture morphology with fracture conductivity decreasing by a factor of 3 and fracture length increasing by about 50%. Many of the subsequent wells were drilled in 2 pattern well clusters, each designed to account for fracture propagation behavior indicated from a microseismic survey. A comparison with an optimal hydraulic fracture design intended to maximize well productivity indicates that most of the well stimulations were suboptimal with rate and cumulative production about ½ that of an optimized design.
The observed changes in fracture conductivity and length over time were unanticipated. Because such data are rarely recorded the variations in fracture morphology that should be of considerable interest to pressure transient analysts. The fracture treatment analysis shows a comparison between the actual fracture treatment and one designed to maximize well productivity and clearly illustrates the potential for well improvement using modern hydraulic fracture design principles.
Multi-stage fracturing technology has widely been used in North American Shale oil & gas industry. Nowadays, the ball-activated frac sleeves with graduated ball seat sizes are still an economic solution for many operators. But traditional ball-activated frac sleeve has physical limitation of ball seats sizes which would limit the number of fracturing stages and would leads an increase in the required surface pressure and horse power.
However, some high-performance multi-stage fracturing completion systems have been developed and are emerging in the marketplace as alternatives to both plug and perf. and traditional ball-activated frac sleeves. This paper will describe three unlimited multi-stage fracturing systems which have recently been developed and can be cemented in place if desired, and have a full-bore internal diameter or as close as possible to the host tubular string after fracturing and without milling-out operation:
1) Coil Tubing (CT) operated sleeve - CT with Bottom-Hole Assembly is used to isolate the target zone and shift sleeve open for each zone.
2) A revolutionary ball-activated frac system - Using a single size ball and ball seat for each zone, this unique frac system can be installed with an unlimited frac stages.
3) Radio-Frequency-Identification (RFID) frac sleeve - By simply dropping RFID tags in wellbore, the RFID frac sleeve system can be run in a well with an unlimited frac stages.
This paper will present how those three frac sleeves work in detail and describe the unique features and capabilities not available in other multi-stage frac systems. It will also discuss simulations of frac efficiency with quantitative comparisons among three frac systems. The analysis will indicate that those three new frac sleeves technologies can be used to optimize hydraulic fracturing operations in regards to both horsepower and stimulated reservoir volume while dramatically reducing overall completion costs.
In preparation for potential exploration success in the Lower Jurassic Posidonia shale gas play in The Netherlands, EBN decided to investigate the possibilities and conditions of a commercial shale gas development in the area concerned. To this end, a thorough inventory and cost analysis of all activities, that are needed to develop such a shale gas play, formed the basis for an assessment of the most relevant subsurface & surface as well as commercial conditions for success. Detailed evaluations of cores, logs and ditch cuttings, detailed fracture modeling, production forecasting, planning of wells, well designs, well pads and locations, evacuation routes and project scenarios (single or multiple drilling rigs) formed part of the study. Apart from the technical and commercial parameters, environmental and legal concerns needed to be addressed. The impact of the industrial activities on the physical and social environment in a densely populated area was mapped.
Copyright 2014, Society of Petroleum Engineers This paper was prepared for presentation at the SPE/EAGE European Unconventional Conference and Exhibition held in Vienna, Austria, 25-27 February 2014. 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. Abstract This paper summarizes the work performed by EBN together with NuTech Energy Alliance for the Netherlands regional study, which aims to address the underexplored pay potential covering both onshore and offshore Netherlands. The paper provides the technical proceedures involved and the usage of available public domain well data for the Netherlands regional field study in order to fulfill the study's two main objectives. First main objective being to identify and analyze the shale play opportunities in unconventional reservoirs of the Lower Jurassic Posidonia Formation and the Namurian Geverik member as well as other shale & marl sections in the area.
Minifrac/diagnostic fracture injection tests (DFITs) are an important and integral part of hydraulic fracture design and reservoir evaluation. Models for analysis of the before and after closure data have been developed. While several models exist and are being used to analyze the after closure data, before closure analysis (BCA) is not widely used, and only a handful of models have been developed. Additionally, the models are based on similar approaches and assumptions. This paper introduces a new BCA model based on rigorous treatment of the fluid flow equations in the fracture and the formation. In this new model, the assumptions of linear leakoff and short injection time for a minifrac test are made. In general, these assumptions are valid. In unconventional reservoirs, where permeability is expected to be very low, the assumption of linear leakoff is particularly valid and would last most of the duration of the before closure period. In most minifrac tests, the injection time is relatively small with respect to after shut-in time, which validates this new model assumption of short injection time. Fracture stiffness is a critical parameter when using this model, which can be easily calculated or measured from logging or experimental data. By using the before closure model presented here, formation permeability could be estimated by interpretation of the slope of straight line in the specialized Cartesian plot using before closure data.
This paper details the development of the new model and compares it to existing models. In addition, several field examples from unconventional formations are presented and analyzed using various techniques, demonstrating the applicability of this new model. The results are also compared to the after closure analysis (ACA).
Organic-rich shale gas reservoirs have various complexities related to the physics of gas storage and transport. Traditionally, the OGIP in shales is calculated by the sum of the adsorbed-gas and the free-gas, as an analog of the CBM reservoirs. However, as noted by a few authors, the free-gas volume must be corrected for presence of adsorbed-gas, assuming all gas storage occurs in kerogen. Even with such correction, shales are still complex reservoirs in terms of flow characteristics. The contribution of viscous, diffusive, and slip forces in nano-scale conduits cause the permeability to be higher than its value expected by Darcy’s law.
A new model is developed to address the effect of the adsorbed-gas volume on the micropore storage capacity. The relative fraction of adsorbed-gas volume is treated as sorbed-phase saturation. The initial free-gas volume is then calculated by subtracting any non-free-gas saturation from the effective void volume. We have extended this concept to a gas material balance equation through which the free-gas volume is dynamically adjusted during depletion. The SLD adsorption model is used to evaluate sorbed-phase density and volume. To address the complexity in gas flow, permeability of the reservoir model is a function of pressure to determine the impact of advection, slippage and diffusion mechanisms. The permeability is calculated via a multi-mechanism flow model. Finally, we utilized the dynamically-corrected permeability in parallel with dynamically-corrected porosity to simulate the primary recovery of a shale gas reservoir.
The new models successfully describe the unique characteristics of shale reservoirs and correct the conventional methods for overestimation of reserves and underestimation of permeability. The format of the final material balance equation and the flow model used here keep the conventional reservoir engineering framework, which are familiar to the
engineers, but with some modifications.
This paper describes the major differences in production performance between liquid-rich shale reservoirs (LRSRs) and conventional reservoirs undergoing depletion recovery. We “map” the transition from conventional depletion performance (oil recovery and producing GOR) to “shale” depletion performance in terms of permeability. The recent research showed that depletion performance for LRSRs is fundamentally different from conventional reservoirs, which is well documented in the literature. This paper attempts to answer the questions - what differentiates conventional from (ultra-tight) shale depletion performance, and when is conventional performance invalid?
Our understanding of LRSRs depletion performance is only now being understood, based on modeling studies and field performance. Quantifying differences in LRSRs depletion performance from conventional reservoirs is important for proper engineering and development of these new resources. Production forecasting and recovery enhancement is a direct result of quantified depletion performance.
Results,Observations, and Conclusions
In this study we compare depletion performance for permeabilities ranging from 10nD to 10D, with PVT and rock properties being the same for all cases. We define a similar “economic” well performance for each permeability-case studied. Our results show that conventional reservoir performance, depending somewhat on initial fluid system, is observed for k>0.5md, while ultra-tight “shale” performance is found for k<1000nD (0.001md), with a gradual transition between these permeability values and shale-like depletion performance appearing already at 0.01md.
Significance of subject matter
Oil recovery factor is a highly ambiguous term for LRSRs with k<0.001md because the (arbitrarily) assigned drainage volume is inversely proportional with recovery factor, even though increasing drainage volume has almost no impact on oil rate or long-term cumulative oil produced; average reservoir pressure is also ambiguous for the same reasons.
Most of the conventional and unconventional reservoirs use viscous fluid systems for hydraulic fracturing due to various reasons such as, good proppant transport, less fluid loss, less pumping friction pressure etc. Salt is often introduced as part of the fluid system for clay protection as well as to increase hydrostatic pressure resulting in lesser surface pressure. The paper investigates the effect of salt concentration on reduction on viscosity for different types of polymers used in fracturing fluids.
Different polymers such as guars, HPG, CMHPG, CMC, and Bio-polymers are used for preparation of fracturing fluids. KCl salts at different concentrations were mixed with the different polymers at room temperature and the change in viscosity was observed at 511-1/sec shear rate. Effect of salt on hydration rate was also observed at room temperature on the different polymers. A hydration time of up to 60 min. was maintained. Plots with different polymers were compared at fixed salt concentrations to understand what polymers have more severe effect. It was observed that the CMC category fluids have a high reduction in viscosity with the salt content than other fluids. A chemical explanation was also given to understand the salt effect on different polymer structures.
Many of the offshore wells use seawater for preparation of fracturing fluids which have high salt concentrations. Even drilling fluids use different polymers at various salt concentrations to increase cutting stability as well as mud weight. Formation water may have high salt content. When the drilling fluids or stimulation fluids mix with the formation brine there can be a high reduction of viscosity resulting in poor proppant or cuttings transport. The study will help in making decisions in choosing polymers and adjusting viscosity considering the salt effect.
This paper addresses the problems identified in current shale reservoir characterization practices. We also provide alternative approaches with relevant reflections on the determination of volumes in-place. Rock properties in unconventional reservoirs such as shales is of paramount importance. By comparison with conventional reservoirs, fluids are present not only in the intergranular porous media but also within the fine texture of the rock matrix (Clays, Kerogen and
Micro-Fractures) which usually are only recoverable with the aid of suitable stimulation and completion technologies. This paper questions current engineering practices related with the assumption of unrealistic cut-offs in the petrophysical
analyses which in turn may result in dangerously misleading estimates of in place volumes and thus inadequate development decisions being made.
The adsorption capacity of clays has been documented with observations on the correlations between the percentages of clay minerals in the rock and Langmuir volume (VL) determined in laboratory measurements of gas content from core
samples by means of Langmuir isotherms. Therefore it should be no surprise that clays in shale gas reservoirs are known to adsorb hydrocarbon gases and may contribute to the production when properly stimulated. We therefore recommend
that corrections for clay effects should not be arbitrarily applied in the petrophysical analysis of electric logs. The use of a total porosity-total water saturation model will help to avoid shortcomings in total gas in-place determination. Additional
reasons for the avoidance of clay porosity corrections; include the fact that there are no tools capable of differentiating between free gas and adsorbed gas.
Total porosity and water saturation methods give rise to total gas content determination with the appropiate model. Adsorbed gas content estimate, may be obtained by correlating geochemical data based on gas content from laboratory experiments and rock density measured on core and or logs.