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Abstract Unconventional resource plays, herein referred to as source rock plays, have been able to significantly increase the supply of hydrocarbons to the world. However, majority of the companies developing these resource plays have struggled to generate consistent positive cash flows, even during periods of stable commodity prices and after successfully reducing the development costs. The fundamental reasons for poor financial performance can be attributed to various reasons, such as; rush to lease acreage and drill wells to hold acreage, delayed mapping of sweet spots, slow acknowledgement of high geological variability, spending significant capital in trial and errors to narrow down optimal combinations of well spacing and stimulation designs. The objective of this paper is to present a systematic integrated multidisciplinary analysis of several unconventional plays worldwide which, if used consistently, can lead to significantly improved economics. We present an analysis of several unconventional plays in the US and Argentina with fluid systems ranging from dry gas to black oil. We utilize the publicly available datasets of well stimulation and production data along with laboratory measured core data to evaluate the sweet spots, the measure of well productivity, and the variability in well productivity. We investigate the design parameters which show the strongest correlation to well productivity. This step allows us to normalize the well productivity in such a way that the underlying well productivity variability due to geology is extracted. We can thus identify the number of wells which should be drilled to establish geology driven productivity variability. Finally, we investigate the impact of well spacing on well productivity. The data indicates that, for any well, first year cumulative production is a robust measure of ultimate well productivity. The injected slurry volume shows the best correlation to the well productivity and "completion normalized" well productivity can be defined as first year cumulative production per barrel of injected slurry volume. However, if well spacing is smaller than the created hydraulic fracture network, the potential gain of well productivity is negated leading to poor economics. Normalized well productivity is log-normally distributed in any play due to log-normal distribution of permeability and the sweet spots will generally be defined by most permeable portions of the play. Normalized well productivity is shown to be independent of areal scale of any play. We show that in every play analyzed, typically 20-50 wells (with successful stimulation and production) are sufficient to extract the log-normal productivity distribution depending on play size and target intervals. We demonstrate that once the log-normal behavior is anticipated, creation of production profiles with p10-p50-p90 values is quite straightforward. The way the data analysis is presented can be easily replicated and utilized by any operator worldwide which can be useful in evaluation of unconventional resource play opportunities.
Abstract Fiber-optic cables cemented outside of the casing of an unconventional well measure cross-well strain changes during fracturing of neighboring wells with low-frequency distributed acoustic sensing (LF-DAS). As a hydraulic fracture intersects an observation well instrumented with fiber-optic cables, fracture fluid injected at ambient temperatures can cool a section of the sensing fiber. Often, LF-DAS and distributed temperature sensing (DTS) cables are run in tandem, enabling the detection of such cooling events. The increasing use of LF-DAS for characterizing unconventional hydraulic fracture completions demands an investigation of the effects of temperature on the measured strain response by LF-DAS. Researchers have demonstrated that LF-DAS can be used to extract the temporal derivative of temperature for use as a differential-temperature-gradient sensor. However, differential-temperature-gradient sensing is predicated on the ability to filter strain components out of the optical signal. In this work, beginning with an equation for optical phase shift of LF-DAS signals, a model relating strain, temperature, and optical phase shift is explicitly developed. The formula provides insights into the relative strength of strain and temperature effects on the phase shift. The uncertainty in the strain-rate measurements due to thermal effects is estimated. The relationship can also be used to quantify uncertainties in differential-temperature-gradient sensors due to strain perturbations. Additionally, a workflow is presented to simulate the LF-DAS response accounting for both strain and temperature effects. Hydraulic fracture geometries are generated with a 3D fracture simulator for a multi-stage unconventional completion. The fracture width distributions are imported by a displacement discontinuity method program to compute the strain-rates along an observation well. An analytic model is used to approximate the temperature in the fracture. Using the derived formulae for optical phase shift, the model outputs are then used to compute the LF-DAS response at a fiber-optic cable, enabling the generation of waterfall plots including both strain and thermal effects. The model results suggest that before, during, and immediately following a fracture intersecting a well instrumented with fiber, the strain on the fiber drives the LF-DAS signal. However, at later times, as completion fluid cools the observation well, the temperature component of the LF-DAS signal can equal or exceed the strain component. The modeled results are compared to a published field case in an attempt to enhance interpretation of LF-DAS waterfall plots. Finally, we propose a sensing configuration in order to identify the events when "wet fractures" (fractures with fluids) intersect the observation well.
Abstract There are mainly two types of solids in the oil field waters; Suspended Solids (SS) and Total Dissolved Solids (TDS). While it is easy to remove SS from water, removal of TDS requires the application of advance filtration techniques such as reverse osmosis or ultra-filtration. Because these techniques cannot handle high volumes of the oilfield waters with high TDS content, produced waters originated from hydraulic fracturing activities cannot be treated by using these advance technologies. Thus, in this study we concentrated on the pretreatment of these waters. We investigated the feasibility of the Coagulation, Flocculation, and Sedimentation (CFS) process as pretreatment method to reduce mainly SS in Produced Water (PW) samples. We collected samples from 14 different wells in the Permian Basin. First, we characterized the water samples in terms of pH, SS, TDS, Zeta potential (ZP), Turbidity, Organic matter presence and different Ion concentration. We tested varying doses of several organic and inorganic chemicals, and on treated water samples we measured pH, TDS, SS, Turbidity, ZP and Ions. Then, we compared obtained results with the initial PW characterizations to determine the best performing chemicals and their optimal dosage (OD) to remove contaminants effectively. The cation and anion analyses on the initial water samples showed that TDS is mainly caused by the dissolved sodium and chlorine ions. ZP results indicated that SS are mainly negatively charged particles with absolute values around 20 mV on average. Among the tested coagulants, the best SS reduction was achieved through the addition of ferric sulfate, which helped to reduce the SS around 86%. To further lessen SS, we tested several organic flocculants in which the reduction was improved slightly more. We concluded while high TDS in the Permian basin does not implement a substantial risk for the reduction of fracture conductivity, SS is posing a high risk. Our study showed, depending on components of the initial PW, reuse of the pretreated water for fracturing may minimize fracture conductivity damage.
Abstract The vast shale gas and tight oil reservoirs cannot be economically developed without multi-stage hydraulic fracture treatments. Owing to the disparity in the density of natural fractures and the different in-situ stress conditions in these formations, micro-seismic fracture mapping has shown that hydraulic fracture treatments develop a range of large-scale fracture networks. The effect of these various fracture geometries on production is a subject matter in question. The fracture networks approximated with micro-seismic mapping are integrated with a commercial numerical production simulator that discretely models different network structures. Two fracture geometries have been broadly proposed, i.e., orthogonal and transverse. The orthogonal pattern represents a network with cross-cutting fractures orthogonal to each other, whereas transverse profile maps uninterrupted fractures achieving maximum depth of penetration into the reservoir. The response for a single stage is further investigated by comparing the propagation of each stage to be dendritic versus planar. A dendritic propagation is a bifurcation of the induced hydraulic fracture due to the intersection with the natural fracture (failure along the plane of weakness). For the same injected fracture treatment volume, the transverse network attains a higher penetration into the reservoir, achieves a higher stimulated reservoir volume (SRV), and produces around 40-65% more than the orthogonal network over a timespan of 10 years. The SRV will largely dictate the drainage area in a tight environment. The cumulative production rises until the pressure drawdown reaches the extent of the fracture fairway. For the orthogonal network, the unstimulated reservoir boundary is reached at a sooner time than the transverse network. It is found that by increasing the fracture spacing in both the networks from 100 ft to 150 ft, the relative production was enhanced in the orthogonal network by 41%, but when it was further increased to 200 ft- there was a minor drop (not increase) in the relative production (4.5%). For an infinite conductivity fracture, the width of the fracture has minimal effect on oil and gas production. For the dendritic pattern, the size of the SRV created due to the interaction between the induced and natural fractures largely depends on the length of natural fractures and the point of interaction (center, off-center, or extremity). Effect of length, distance of natural fracture from wellbore, and the point of interaction is evaluated. A novel approach for reservoir simulation is used, where porosity (instead of permeability) is used as a scaling parameter for the fracture width. The forward modeling effort, including the comparative fracture geometries setup, induced, and natural fracture interaction parametric study, is unique.
Abstract Unconventional reservoirs, mainly shale oil and natural gas, will continue to significantly help meet the ever-growing energy demands of global markets. Being complex in nature and having ultra-tight producing zones, unconventionals depends on effective well completion and stimulation treatments in order to be successful and economical. Within the last decade, thousands of unconventional wells have been drilled, completed and produced in North America. The scope of this work is exploring the primary impact of completion parameters such as lateral length, frac type, number of stages, proppant and fluid volume effect on the production performance of the wells in unconventional fields. The key attributes in completion, stimulation, and production for the wells were considered in machine learning workflow for building predictive models. Predictive models based on Neural Networks, Support Vector Machines or Decision Tree Based ensemble models, serves as mapping function from completion parameters to production in each well in the field. The completion parameters were analyzed in the workflow with respect to feature engineering and interpretation. This analysis resulted in key performance indicators for the region. Then the optimum values for the best production performing completions were identified for each well. Predictive models in the workflow were analyzed in accuracy and best model is used to understand the impact of completion parameters on the production rates. This study outlines an overall machine learning workflow, from feature engineering to interpretation of the machine learning models to quantify the effects of completion parameters on the production rate of the wells in unconventional fields
Zhang, Fengyuan (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum Beijing) | Emami-Meybodi, Hamid (Department of Energy and Mineral Engineering and EMS Energy Institute, The Pennsylvania State University)
Abstract This study presents a new type-curve method to characterize hydraulic fracture (HF) attributes and dynamics by analyzing two-phase flowback data from multi-fractured horizontal wells (MFHWs) in hydrocarbon reservoirs.The proposed method includes a semianalytical model, as well as a workflow to estimate HF properties (i.e., initial fracture pore-volume and fracture permeability) and HF closure dynamics (through iterating fracture compressibility and permeability modulus).The semianalytical model considers the coupled two-phase flow in the fracture and matrix system, the variable production rate at the well, as well as the pressure-dependent reservoir and fluid properties. By incorporating the contribution of fluid influx from matrix into the fracture effective compressibility, a new set of dimensionless groups is defined to obtain a dimensionless solution for type-curve analysis. The accuracy of the proposed method is tested using the synthetic data generated from six numerical simulation cases for shale gas and oil reservoirs. The numerical validation confirms the unique behavior of type curves during fracture boundary dominated flow and verifies the accuracy of the type-curve analysis in the characterization of fracture properties. For field application, the proposed method is applied to two MFHWs in Marcellus shale gas and Eagle Ford shale oil.The agreement of interpreted results between the proposed method and straight-line analysis not only demonstrates the practicality in field application but also illustrates the superiority of the type-curve method as an easy-to-use technique to analyze two-phase flowback data. The analysis results from both of the field examples reveal the consistency in the estimated fracture properties between the proposed method and long-term history matching.
Kong, Lingyun (University of North Dakota) | Ishutov, Sergey (University of Alberta) | Hasiuk, Franciszek (Kansas Geological Survey, University of Kansas) | Xu, Chicheng (Aramco Americas: Aramco Research Center–Houston (Corresponding author)
Summary Geoscientific and engineering experiments in petrophysics, rock physics, and rock mechanics depend on multiple, costly, and sometimes rare samples used to characterize the properties of natural rocks. Testing these samples helps in modeling various hydrocarbon recovery and stimulation scenarios, as well as understanding the fluid-rock interactions in the subsurface under various pressure and temperature conditions. Over the last decade, 3D printing has matured to become a more commonly available tool to enable repeatable experiments with controllable materials and pore system geometries to investigate petrophysical, geomechanical, and geophysical properties of porous rocks. This review introduces the development, characteristics, and capabilities of 3D printing technology that are specifically used in research. Applications in the realm of petrophysics highlight the issues of replicating the pore network geometry and subsurface physics, aiming at understanding fluid flow in porous media problems. Using 3D-printed models in rock mechanics experiments focuses on generating comparable geomechanical properties and reproducing fractures, joint surfaces, and other rock structures, whereas in rock physics, geophysical forward modeling is highlighted to take advantage of 3D printing technology. By summarizing the recent advances in 3D printing as applied to petrophysics, rock physics, and rock mechanics, this review paper presents the current state of the art and the challenges in scale, cost, time, and materials, as well as the directions for advancing this frontier discipline to answer various fundamental questions regarding porous media research using 3D printing technology.
Summary This work studies 1D steady-state flow of gas from compressible shale matrix subject to water blocking toward a neighboring fracture. Water blocking is a capillary end effect causing wetting phase (e.g., water) to accumulate near the transition from matrix to fracture. Hydraulic fracturing is essential for economical shale gas production. Water is frequently used as fracturing fluid, but its accumulation in the matrix can reduce gas mobility and production rate. Gas transport is considered at a defined pressure drop. The model accounts for apparent permeability (slip), compressibility of gas and shale, permeability reduction, saturation tortuosity (reduced relative permeability upon compaction), and multiphase flow parameters like relative permeability and capillary pressure, which depend on wettability. The behavior of gas flow rate and distributions of gas saturation, pressure, and permeability subject to different conditions and the stated mechanisms is explored. Water blockage reduces gas relative permeability over a large zone and reduces the gas flow rate. Despite gas flowing, strong capillary forces sustain mobile water over the entire system. Reducing drawdown gave lower driving force and higher resistance (by water blockage) for gas flow. The results show that 75% reduction of drawdown made the gas flow rate a couple orders of magnitude lower compared to if there was no blockage. The impact was most severe in more water-wetsystems. The blockage caused most of the pressure drop to occur near the outlet. High pressure in the rest of the system reduced effects from gas decompression, matrix compression, and slip-enhanced permeability, whereas rapid gradients in all these effects occurred near the outlet. Gas decompression resulted in an approximately 10 times higher Darcy velocity and pressure gradient near the outlet compared to inlet, which contributed to removing blockage, but the added resistance reduced the gas production rate. Similarly, higher gas Corey exponent associated gas flow with higher pressure drop. The result was less blockage but lower gas production. Slip increased permeability, especially toward the outlet, and contributed to increase in gas production by 16%. Significant matrix compression was associated with permeability reduction and increased Corey exponent in some examples. These effects reduced production and shifted more of the pressure drop toward the outlet. Upstream pressure was more uniform, and less compression and permeability reduction were seen overall compared to a system without water blockage.
Summary Wettability is an important petrophysical property, which governs irreducible fluid saturations, relative permeability, and fluid invasion in rocks. Unlike conventional reservoirs, which have relatively uniform pore surface properties, the concept of wettability is not clear in organic-rich tight reservoirs. These rocks do not only have a nanoporous system but also possess multiple pore types with different interfacial affinities. Previous studies have shown that the unconventional reservoirs consist of three major pore types: inorganic pores (assumed to be water-wet), organic pores (assumed to be oil-wet, controlled by organic matter and thermal maturity), and mixed-wet pores (controlled by organic-inorganic distribution) (Curtis et al. 2012). This study revisits the concept of pore-type partitioning in tight rocks. We propose and demonstrate a new workflow to evaluate pore partitioning. First, all the specimens were vacuum dried at 100°C for 6 days to remove the free fluids until the weight stabilized. Total porosity was estimated as the sum of residual liquid volume [using nuclear magnetic resonance (NMR)] and gas-filled volume [using helium high-pressure pycnometer (HPP)]. The companion specimens from two formations (Eagle Ford and Wolfcamp B) were subjected to multiple injection cycles: starting with imbibition, then counter imbibition, and finally step pressurization with the replacing phase. During this process, we used brine-then-dodecane and dodecane-then-brine as the injection fluid sequences. The companion samples were continuously monitored by both gravimetric and NMR measurements until equilibration. Relative fractions of both replaced and replacing phases were calculated from sample weights and pore-fluid volumes. The new approach not only classifies the connected pore network into three categories—oil-wet, water-wet, and mixed-wet—but also quantifies their respective proportions. The mixed-wet pore is defined as the pore fraction, in which both oil and water can replace air under capillary suction. We observe that the behavior of mixed-wet pores is different among formations: they prefer brine over oil in Wolfcamp B shale, while they prefer oil over brine in the Eagle Ford Formation. Unlike conventional wettability assessments, from which an overall wettability is provided, the novelty of this method is to clearly classify different pore types and their distributions. The concept of fractional wettability is highlighted for organic-rich tight rocks, and the contribution of mixed-wet pores in relative flow is emphasized. Hydraulic fracturing is a necessary stimulation process for tight reservoirs, in which the usage of fracturing fluid can affect formation performance. During well completion, water blockage is more likely to happen in the Wolfcamp B Formation than Eagle Ford Formation. Due to the capillary preference of mixed-wet pores, the water blockage might aid the Wolfcamp Formation to boost initial production, however, at a later stage, damage the formation. The workflow thus is promising to fully describe the pore network in tight formations, in which pore-type partitioning is a more reasonable concept than wettability.
Summary This study focuses on the development of an analytical model to predict the long-term productivity of channel-fractured shale gas/oil wells. The accuracy was verified by comparing productivity calculated by the proposed model with numerical results. Sensitivity analysis was conducted to analyze significant parameters on the performance of channel fracturing. Field application of the model was conducted using production data obtained from an Eagle Ford Formation dry gas well, which was completed using channel fracturing. The procedure for estimating reservoir and stimulation parameters from production data was provided. The results indicated that the equivalent fracture width obtained from our model is consistent with the inversion of cubic law. Comparison with numerical simulations demonstrated that the proposed model might under- or overestimate well productivity, with mean absolute percentage error (MAPE) values of less than 8%. Sensitivity analysis indicated that, with the increase of fracture width, fracture half-length, and matrix permeability, the productivity of channel-fractured wells increases disproportionately. In addition, well productivity will increase as the ratio of the pillar radius to the length of channel fracture decreases, provided that the proppant pillars are stable and the fracture width is held constant. Under the conditions of smaller fracture width and larger matrix permeability, the effect of using channel fracturing to increase well productivity is more significant. However, as the fracture width becomes large, the benefits of channel fracturing will diminish. The case study indicated that the shale gas productivity estimated by the proposed model matches well with field data, with MAPE and R of 12.90% and 0.93, respectively. The proposed model provides a basis for optimizing the design of channel fracturing.