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Xu, Guoqing (Sinopec Research Institute of Petroleum Engineering (Corresponding author) | Han, Yujiao (email: firstname.lastname@example.org)) | Jiang, Yun (Sinopec Research Institute of Petroleum Engineering) | Shi, Yang (Research Institute of Petroleum Exploration & Development, PetroChina (Corresponding author) | Wang, Mingxian (email: email@example.com)) | Zeng, XingHang (Research Institute of Petroleum Exploration & Development, PetroChina (Corresponding author)
Summary Spontaneous imbibition (SI) is regarded as an effective method to improve the oil recovery in a tight sandstone reservoir, which leads to a significant change in fracturing design and flowback treatment. However, a longtime shut-in period would aggravate the retention of fracturing fluid, which is in contradiction with high production in the field. It is imperative to understand how SI works during shut-in time, so as to maximize the effect of imbibition in oil recovery enhancement. In this study, a series of experiments were conducted to simulate the status of residual oil saturation so that the inner mechanism of imbibition on oil recovery can be investigated. Low-field nuclear magnetic resonance (LF-NMR) was used to provide direct observation of phase changes in different pore sizes. The experimental results show a positive effect of imbibition on residual oil reduction. This phenomenon further elucidates the observations made during the well shut-in, soaking period, and low flowback efficiency. This study aims to understand the mechanism of SI behavior and help to improve the accuracy of production prediction.
Ju, Yang (China University of Mining and Technology (Corresponding author) | Wu, Guangjie (emails: firstname.lastname@example.org or email@example.com)) | Wang, Yongliang (China University of Mining and Technology) | Liu, Peng (China University of Mining and Technology) | Yang, Yongming (China University of Mining and Technology)
Summary In this paper, we introduce the entropy weight method (EWM) to establish a comprehensive evaluation model able to quantify the brittleness of reservoir rocks. Based on the evaluation model and using the adaptive finite element-discrete element (FE-DE) method, a 3D model is established to simulate and compare the propagation behavior of hydraulic fractures in different brittle and ductile reservoirs. A failure criterion combining the Mohr-Coulomb strength criterion and the Rankine tensile criterion is used to characterize the softening and yielding behavior of the fracture tip and the shear plastic failure behavior away from the crack tip during the propagation of a fracture. To understand the effects of rock brittleness and ductility on hydraulic fracture propagation more intuitively, two groups of ideal cases with a single failure mode are designed, and the fracture propagation characteristics are compared and analyzed. By combining natural rock core scenarios with single failure mode cases, a comprehensive evaluation index BIf for reservoir brittleness and ductility is constructed. The simulation experiment results indicate that fractures in brittle reservoirs tended to form a complex network. With enhanced ductility, the yielding and softening of reservoirs hamper fracture propagation, leading to the formation of a simple network, smaller fracture area (FA), larger fracture volume, and the need for higher initiation pressure. The comprehensive index BIf can be used to define brittleness or ductility as the dominant factor of fracturing behavior. That is, 0 < BIf ≤ 0.46 indicates that the reservoir has enhanced ductility and ductile fracturing prevails; 0.72 < BIf < 1 indicates that the reservoir has enhanced brittleness and brittle fracturing prevails; and 0.46 < BIf ≤ 0.72 means a transition from brittle to ductile fracturing. Based on fitting analysis results, the relationship between the calculated FAr and BIf is constructed to quantify the influence of reservoir brittleness and ductility on fracturing. The study provides new perspectives for designing, predicting, and optimizing the fracturing stimulation of tight reservoirs with various brittleness and ductility.
Yang, Ruiyue (China University of Petroleum) | Hong, Chunyang (China University of Petroleum) | Huang, Zhongwei (China University of Petroleum) | Wen, Haitao (China University of Petroleum) | Li, Xiaojiang (Sinopec Research Institute of Petroleum Engineering) | Huang, Pengpeng (China University of Petroleum) | Liu, Wei (China University of Petroleum) | Chen, Jianxiang (China University of Petroleum)
Summary Multistage hydraulic fracturing is widely used in developing tight reservoirs. However, the economic and environmental burden of freshwater souring, transportation, treatment, and disposal in hydraulic fracturing operations has been a topic of great importance to the energy industry and public alike. Waterless fracturing is one possible method of solving these water‐related issues. Liquid nitrogen (LN2) is considered a promising alternate fracturing fluid that can create fractures by coupled hydraulic/thermal loadings and, more importantly, pose no threats to the environment. However, there are few laboratory experiments that use LN2 directly as a fracturing fluid. In this work, we examine the performance of LN2 fracturing based on a newly developed cryogenic‐fracturing system under true‐triaxial loadings. The breakdown pressure and fracture morphologies are compared with water fracturing. Moreover, fracture‐initiation behavior under cryogenic in‐situ conditions revealed by cryo‐scanning electron microscopy (cryo‐SEM) is presented, and the role of thermal stress is quantified by a coupled thermoporoelastic‐damage numerical simulation. Finally, the potential application considerations of LN2 fracturing in the field site are discussed. The results demonstrate that LN2 fracturing can lower fracture initiation and propagation pressure and generate higher conductive fractures with numerous thermally induced cracks in the vicinity of the wellbore. Thermal gradient could generate enormously high‐tensile hoop stress and bring about extensive rock damage. Fracture‐propagation direction is inclined to be influenced by the thermal stress. Furthermore, phase transition during the fracturing process and low fluid viscosity of LN2 can also facilitate the fracture propagation and network generation. The key findings obtained in this work are expected to provide a viable alternative for the sustainable development of tight‐reservoir resources in an efficient and environmentally acceptable way.
Oil production from shale and tight formations accounted for more than half of total US oil production in 2015 (EIA, 2016). Such amount is expected to grow significantly as the active development of low-permeability reservoirs continues. The current technique to produce shale oil is through primary depletion using horizontal wells with multiple transverse fractures. The oil recovery in shale oil reservoirs is less than 10% (Sheng, 2015a), or 3–6%, according to the EIA 2013 report (US DOE, 2013). The oil recovery in tight formations is also low.
Recently unconventional gas resources including the shallow biogenic gas reservoirs have received great attention around the world due to technical advances in the field development and corresponding large in-place resources. However, the technologies needed for the effective development of unconventional reservoirs are still behind the industry needs, for example the gas recovery rates from these unconventional resources are still very low.
The Miocene Gachsaran Formation across Onshore Abu Dhabi and Dubai possesses high potential of generating shallow biogenic gas. To understand and evaluate its capability for a promising gas resources a dynamic model and field development plan were generated based on a detail G&G analysis. The Gachsaran biogenic gas potential falls under the category of unconventional resources due to the existence of adsorbed gas within the organic matter and clay.
The paper provides a detailed numerical simulation approach from a modified commercial simulators to simplify analytical solutions for adsorbed gas in-place calculation and full field development plan. The construction of dynamic model to tackle the growing advances in drilling and stimulation technologies for such complex tight reservoirs have become possible. These reservoirs are still challenging to produce due to their complex geology, tightness and requirements of advance production technologies such as hydraulic fracturing to achieve economical production rates.
The gas flow mechanisms in nano-pores cannot be simply described by Darcy flow equation. In addition, due to large-scale fracturing, the conventional single porosity model is not enough to simulate the characteristics of these source rock type reservoirs. Furthermore, advanced simulation methods such as molecular dynamic simulation are computationally challenging and very time consuming.
To mitigate these challenges, two alternative unique approaches were considered to model these reservoirs: (1) application of analytical methods to characterize the primary characteristics of nano-pores, and (2) extending the conventional simulator to effectively model flow from the nano-pores gas reservoirs. The study describes the theory and application utilized to modify and enhance the capability of conventional simulator. Consequently, to properly estimate the adsorbed gas in-place and integrate the effects of Langmuir gas desorption and gas diffusion effects. Therefore, the dual-porosity model was built and coupled with local grid refinement to capture the associated hydraulic fracture design and properties. This robust modeling approach has provided an enhancement in the field development planning of such a complex regional scale unconventional reservoir.
Abstract Aimed at sharing the unconventional wisdom gained from a hydraulic fracturing monitoring case study in the Montney tight gas play, the work showcases the ability of 4D modeling of collective behaviors of microseismic events to chase the frac fluid and navigate the spatiotemporal fracture evolution. Moreover, microseismicity-derived deformation fields are integrated with volumetric estimates made by rate transient analysis to calibrate spatially-constrained SRV models. Through the case study, we give evidence of fracture containment, evaluate the role of natural fractures and the use of diverting agents, estimate cluster efficiencies, conduct analytical well spacing optimization, model productivity decline induced by communication frac-hits from offsets, and provide contributing fracture dimensions and numerical production forecasts. To support the interpretations, we supplement the work by the results of 3D physics-based analytical modeling and multi-phase numerical simulations, and the findings are then validated using two extensive datasets: production profiles acquired by fiber optic DAS, and reservoir fluid fingerprints extracted from mud logs. Besides describing the evolution of seismicity during the treatment, the applied integrated fracture mapping process gives a more reliable and unique SRV structure that streamlines forward modeling and simulations in unconventional reservoirs as well as contributes to solving inverse problems more mechanistically.
Eltahan, Esmail (The University of Texas at Austin) | Bordeaux Rego, Fabio (The University of Texas at Austin) | Yu, Wei (The University of Texas at Austin, Sim Tech LLC) | Sepehrnoori, Kamy (The University of Texas at Austin)
Abstract Water invasion, associated with hydraulic fracturing, often causes hydrocarbon-mobility hindrance, known as water blocking. The effect on productivity is largely dependent on saturation profiles inside fractures and formation matrix. Enhancement to hydrocarbon recovery has been reported in some field cases after shutting in wells for long time periods. Here we conduct numerical-simulation studies to investigate the effect of well shut-in on initial productivity and long-term recovery. We replicate post-fracturing conditions with an extensive fracture network that intermeshes with formation matrix. The models are designed using either logarithmically spaced, locally refined grid or embedded discrete fracture model (EDFM). Starting with varying initial fluid distributions, we compare productivity and recovery of two cases: one that does not start production until after 32 days of shut-in, and another that starts immediately without soaking. For the initial conditions that favor shut-in, we carry out case studies in attempt to find the ideal shut-in conditions for maximum recovery improvement. Results confirm improvement in early productivity after shut-in for all the considered initial fluid-distribution cases. The majority of cases exhibit net gain in total oil recovery. We report improvement in recovery of as much as 5%, owing to spontaneous imbibition. Imbibition of the injected water into formation matrix causes fluid redistribution and favored mobility for the non-wetting phase, and hence enhanced hydrocarbon productivity. The simulations take into account spontaneous imbibition and gravity segregation, but do not consider geo-mechanical forces, water adsorption or chemical reactions. When capillary forces are neglected, well productivity and recovery decrease, even when the well is not shut in. Such observations underline imbibition counter-current flow as an important production mechanism that should not be neglected in shale-oil-reservoir simulations.
Ogbonnaya, Onyekachi (University of Oklahoma, Norman, Oklahoma, USA) | Wang, Shuoshi (Southwest Petroleum University, Chengdu, China) | Shiau, Benjamin (University of Oklahoma, Norman, Oklahoma, USA) | Harwell, Jeffrey (University of Oklahoma, Norman, Oklahoma, USA)
Abstract Modified in situ CO2 generation was explored as an improved tool to deliver CO2 indirectly to the target liquid rich shale formations. Once injected, the special CO2- generating compound, urea, decomposes deep in fractures at the elevated temperature conditions, and releases significant amounts of CO2. For field implementation, the minimum surface facility is required other than simple water injection equipment. Injection of urea solution may be easier and cheaper than most gas injection approaches. In this effort, in situ CO2 treatment and designs were carried out on a group of Woodford shale core samples. The oil saturated shale cores were soaked in different urea solutions kept in pressurized (1500 and 4000 psi) and heated extraction vessels at temperature of 250 °F. The adopted treatment step closely simulates the huff-and-puff technique. A series of experiments were run with various ingredients, including brine only, brine plus surfactant, brine plus urea and ternary mixture of brine/surfactant/urea. In addition, the extraction experiments were tested at below and above MMP conditions to decipher the principal recovery mechanism. Based on our preliminary observations, the sample cores did not lose their stability after an extended period of oil extraction with in situ CO2 treatment. The urea only case could recover up to 24% of the OOIP compared to about 6% for the brine only case and 21% for the surfactant only case. Also adding a pre-selected surfactant to the urea slug did not have any benefit. There was no significant difference in oil recovery when the test pressure was below or above MMP. The main recovery mechanisms were oil swelling, viscosity reduction, low interfacial tension and wettability alteration in this effort. Multiple researchers reported successful lab scale CO2 gas extraction EOR experiments for liquid rich shale like upper, middle and lower Bakken reservoir. The best scenario could recover 90% of the OOIP from the shale core samples. The evidences of this effort offer a strong proof of concept of in situ CO2 generation potential for liquid rich shale reservoirs.
Summary Numerous technical papers have been published on the reservoir evaluation of tight sand gas in recent decades. It is believed that tight sand gas is characterized by low permeability, complex pore structure, abnormal pressure, and low gas saturation. Researchers have characterized tight gas in terms of, for example, statistics; and some of them are increasingly interested in the effect of fluid pressure and pore structure on gas saturation. However, there is still a lack of effective experimental and mechanism analysis. The focus of this paper is to investigate the effect of two factors on controlling the tight gas saturation. A method was proposed for determining the in‐situ injection pressure of the DB 2 gas reservoir in the Kuqa area during the gas‐accumulation period, and the result was 1.2 MPa. A polyetheretherketone carbon‐fiber core holder (maximum temperature 180 °C, maximum confining pressure 30 MPa) was designed for the microcomputed‐tomography (CT) simulation experiment. After that, four physical simulation experiments of different fluid pressures (0.1, 0.5, 1.5, and 5.0 MPa) were implemented using X‐ray CT and the new core holder to study the effect of fluid pressure and pore structure on gas saturation. The results show that the fluid pressure and micropore connectivity are important factors for gas‐saturation increase; the number of gas clusters (connected pores containing gas) increases with the increase of fluid pressure and the maximum volume of gas clusters increases with the increase of pore connectivity. The connected pores with the largest volume are an important source of gas‐saturation contribution. The three types of modes (the blowing balloon mode, stitching mode, and composite mode) of microscopic gas‐cluster formation are discussed. The blowing balloon mode is key to gas‐saturation growth in the period of low fluid pressure or the early stage of the injection process. The stitching mode is key to gas‐saturation growth in the period of high fluid pressure or the late stage of the injection process. The above research system investigates the quantitative control of fluid parameters (pressure) and reservoir parameters (pore structure) on gas saturation, which might change the situation where previous research was too focused on the pore‐structure and fluid‐pressure characterization, with a lack of quantitative control analysis of reservoir gas saturation. It provides a valuable reference and framework for the reader to conduct further quantitative research on tight gas saturation.
The application of crushed rock analysis for unconventional formation evaluation has become standard in core analysis following its introduction for shale gas volumetrics by Luffel and Guidry (1992). Crushing is used to expedite the extraction, drying, and volumetric measurement processes. Critical assumptions of crushed rock analysis include: all pore space is interconnected, crushing should not create entry into any pores that previously were isolated, and the crushed particles are orders of magnitude larger than the representative pore space. The analytical procedures were established to provide reservoir rock and fluid properties, for which log interpretation methods could be developed to match the core and production results.
This study expands on the effect of crushing on core samples beyond the original Devonian shale scope of the Gas Research Institute, GRI, program. Mercury injection capillary pressure (MICP) measurements are incorporated to quantify volumetric and textural changes to the rock fabric from the crushing process. Changes in sample compressibility are also investigated to account for the removal of residual, low compressibility fluids. The objective is to understand potential fundamental changes to the rock to reconcile the crushed, cleaned ambient condition with stressed, subsurface conditions.
Fourteen core samples, at an average frequency of 18’, are selected to represent a variety of lithologies across a 200’ interval of the Wolfcamp A in the Delaware Basin. Each sample was split into three subsamples: one subsample remained intact, one subsample is coarsely crushed to +50-mesh, and the last is crushed and sieved to -20+35-mesh fraction to replicate the particle size common for many crushed rock protocols (Luffel, 1992). All subsamples were cleaned using a sequence of organic solvents and dried at 60°C to remove residual free fluid and interstitial clay bound water (Burger, 2014).
Certain facies showed a higher likelihood for pore alteration with dominant micro-scale pore features flattening, shifting, or re-distributing following the crushing and cleaning process. Mudstone samples experienced increases in compressible pore volume after crushing and extraction as total porosity converged towards GRI helium porosity. The results of this study provide characterization of the connected, effective pore volume using compressibility concepts and comparison to residual fluid volumes. The decision to crush, and the degree of crushing if so, should consider the representative pore sizes of each facies.