With increasing global energy demands, unconventional formations, such as shale rocks, are becoming an important source of natural gas. Extensive efforts focus on understanding the complex behavior of fluids (including their transport in the sub-surface) to maximize natural gas yields. Shale rocks are mudstones made up of organic and inorganic constituents of varying pore sizes (1-500nm). With cutting-edge imaging technologies, detailed structural and chemical description of shale rocks can be obtained at different length scales. Using this knowledge to assess macroscopic properties, such as fluid permeability, remains challenging. Direct experimental measurements of permeability supply answers, but at elevated costs of time and resources. To complement these, computer simulations are widely available; however, they employ significant approximations, and a reliable methodology to estimate permeability in heterogeneous pore networks remains elusive. For this study, permeability predictions obtained by implementing two deterministic methods and one stochastic approach, using a kinetic Monte Carlo algorithm, are compared. This analysis focuses on the effects resulting from pore size distribution, the impact of micro-and macropores, and the effects of anisotropy (induced or naturally occurring) on the predicted matrix permeability. While considering multiple case studies, recommendations are provided on the optimal conditions under which each method can be used. Finally, a stochastic analysis is performed to estimate the permeability of an Eagle Ford shale sample using the kinetic Monte Carlo algorithm. Successful comparisons against experimental data demonstrate the appeal of the stochastic approach.

Producing from liquids-rich, ultra-low-permeability reservoirs requires long, horizontal wells with multiple fractures—a situation that demands a better understanding of well-completion practices in relation to reservoir dynamics to maximize benefit. This paper attempts to augment that understanding through a stochastic reservoir modeling approach. A reservoir simulation model for a typical condensate well in the Eagle Ford liquids-rich area was used in a decision-under-uncertainty framework to identify optimal completion and production strategies. The important factors considered are for fractures (length, conductivity, conductivity endurance, and spacing), reservoir (matrix permeability), fluid (saturation pressure and condensate-gas ratio), and well constraints (bottomhole pressure and rates). The effect of these factors, grouped into decision and uncertainty variables, on well productivity were examined to identify the optimal combination of values for each decision variable, considering the impact of uncertainty variables represented by a statistical metric. Completion techniques and proppant selection that maximize well productivity in conventional or even tight formations by maximizing fracture conductivity are not necessarily optimal for ultra-low-permeability reservoirs. The marginal benefit of higher fracture conductivity diminishes rapidly in such reservoirs, and lower-grade proppants can be used. The optimal completion strategy consists of balancing the effects of decision variables based on a clear objective of maximizing reserves or accelerating production or a specific combination thereof. This is because the variables interact; for example, longer fractures both accelerate production and add reserves (bigger drainage volumes), whereas if drainage volumes interfere, closer fracture spacing can accelerate production without increasing reserves. The rapid falloff in production rates for wells in ultra-low-permeability reservoirs encourages operators to establish high initial rates. In liquids-rich wells, such a strategy can leave a large quantity of unproduced liquids in the fractures that also impedes production rates. At a very low drawdown, however, the well may not even produce. Hence, an optimal production strategy maximizing the liquid yield at the surface should be planned and employed. During the fracture-treatment design process, large uncertainties that affect fracture geometry and properties are often ignored, leading to designs that are suboptimal for well productivity in the field. This study considers decision and uncertainty variables related to both completion and production. Insights developed with respect to the interaction of various factors from the study allow for a fuller understanding and provide practical guidelines for completion and production practices. The dynamic behavior of condensate banks in the presence of hydraulic fractures as it relates to production practices is also examined—this has not been discussed in detail in the literature.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractEffective fracture length is the portion of the propped fracture that cleans up after hydraulic fracturing procedure and contributes to well productivity. Studies indicate that this effective length is often less than 10% of the total propped fracture length. A large portion of our fracture stimulation dollars are wasted! This paper presents a comparative well study performed in the Cement field in south central Oklahoma. Stimulation of the Springer Sands using hydraulic fracturing with conventional low polymer fluids was compared with the use of low molecular weight polymer fracturing fluid. The depth of the three Springer Sands (Cunningham, Britt, and Boatwright) ranges from 12,500 feet to 15,500 feet and have an average permeability range of 0.1 to 5.0 md. This evaluation includes several components.Well production history matching and pressure analyses are used to determine effective fracture length. Results of these analyses are compared with calculated values based on laboratory generated cleanup data for the two fluid systems. Flowback rate, pressure, accumulated volume, viscosity, and polymer content were collected following the fracture stimulation treatments.The fluid systems compared in this study are a conventional low polymer system with gel breakers and a new, low molecular weight polymer system that requires no breakers. Both fluids use borate cross-linking chemistry. The low molecular weight fluid system creates transient, high molecular weight polymer chains at higher pH conditions. After exposure to the formation minerals, the pH drops and it reverts to a clean, nearly Newtonian, low viscosity fluid that causes little conductivity damage.The results of this study show that the use of low molecular weight fracturing fluid provides significant improvements in the effective fracture length over conventional low polymer fracturing fluids. Simple engineering tools have also been developed to evaluate both fluid and proppant selection and job design to achieve improved well performance. It also demonstrated that improved recovery of the fracturing fluid can be achieved at excellent rates without the use of conventional gel breakers.

Estimating the effective permeability and microfracture (MF) conductivity for unconventional reservoirs can be challenging; however, a new method for estimating using a stochastic approach is discussed. This new analysis method estimates matrix permeability and the unpropped and propped MF conductivities during laboratory testing where MFs were propped with ultrafine particles (UFPs). Kinetic Monte Carlo (KMC) simulations form the basis of the method used to estimate effective permeability of the core sample. First, the stochastic model was implemented to calculate effective matrix permeability of a small core taken from unfractured Eagle Ford and Marcellus formation samples using scanning electron microscopy (SEM) images and adsorption data to obtain the pore-size distribution (PSD) within the sample. The KMC approach then evaluated the effect of various parameters influencing the conductivity of laboratory-created MFs. Case studies considered for this work investigate the conductivity improvement of a manmade MF as a function of the UFPs used as proppants that maintain width under high stress, the UFP (proppant) concentration, and the UFP flow perpendicular into a secondary or adjacent MF zone (2ndMF) penetrating the face of an opened MF during flow testing under stress. The leakoff area widths considered were 1, 2, and 3 mm and can be propped or unpropped. Results obtained for the unfractured Eagle Ford and Marcellus samples closely correlate with other computational and experimental data available. For the laboratory-prepared nonpropped and propped MF samples, the effective propped width was determined to have the greatest effect on the MF conductivity, which increased by two orders of magnitude in the presence of the UFPs. The remaining two factors—proppant concentration and length of 2ndMFs—helped improve the effective MF conductivity in a linear manner; the highest proppant concentration and the 2ndMF zone resulted in the highest fracture conductivity achieved. Insight obtained from this study can be used to optimize fracturing designs by including UFPs and to create strategies for maximizing hydrocarbon recovery during development of unconventional resources where MFs are opened during stimulation treatments.

Summary Migration of formation fines has been shown to cause production decline in many wells. Despite the availability of new downhole tools for use in well stimulation and completion, the ability to sustain desired production levels is often plagued with fines migration problems. The solution to this problem is appropriate treatment to mitigate fines migration at its source. This paper describes the use of an ultra-thin tackifying agent (UTTA) for stabilizing fines in high-rate producing or injection wells. This UTTA is applied as part of an initial prepad in fracturing or gravel-packing operations, as a remedial treatment, or as a post-treatment following acid fracturing or matrix acidizing treatments. The primary purpose of UTTA application is to immobilize formation fines so that they will not detach, migrate with flowing fluids, plug the pore channels, and reduce the flow path permeability. Results of laboratory testing indicate that the UTTA system is applicable to most types of formation fines, including coals, sandstones, and carbonates. Once injected into the formation matrix or proppant pack, the UTTA forms a thin film on formation surfaces, encapsulating the fines. Capillary action helps pull the tackifier into the contact points, fixing the particulate in place without plugging the pore throat. The UTTA does not require a shut-in time after its application. The thin film tackifier does not harden, but remains flexible, enhancing the ability of a formation to withstand stress cycling and allowing the formation to handle high shear stress during high flow rates. Introduction Hibbeler et al. (2003) provide an excellent review of fines migration mechanisms. Many investigators have examined factors affecting permeability decline because of fines migration and clay swelling, including salinity changes, pH, and flow rate (Muecke 1979; Gruesbeck and Collins 1982). Migration of formation fines is known to cause severe formation damage during production, limiting the potential production of the well. Various techniques have been developed in the industry over the years as fines-stabilizing solutions to overcome the effects of fines migration (Muecke 1979; Sharma and Sharma 1994). Acidizing has often been used to dissolve fines by "unblocking" and enlarging pore-throat geometry in the formation near the wellbore to increase the permeability of the formation. Production performance in wells that have been acidized or acid-fractured has often been disappointing. High production rates typically last only a short time, followed by a drastic drop in production because of the damage caused by fines plugging. Other chemical treatments, such as the inclusion of clay-stabilizing surfactants as part of the completion fluids, or polymers in remedial operations, have been applied in an effort to minimize fines migration and enhance well productivity (Kalfayan and Watkins 1990; McLaughlin and Weaver 1982; McLaughlin et al. 1976). These treatments commonly require that the treatment fluids be injected deep into the formation matrix, allowing the surfaces of the fines and pores to contact and interact with the treating fluid. Large volumes of treating fluid are often required to achieve the desired results. Most such treatment fluids provide only temporary solutions because they tend to desorb with time and with the production of fluids from the well.