Lei, Zhengdong (Research Institute of Petroleum Exploration and Development, PetroChina) | Yang, Xinping (Exploration and Development Research Institute of Xinjiang Oilfield Company) | Li, Xiaoshan (Exploration and Development Research Institute of Xinjiang Oilfield Company) | Hu, Die (University of Calgary) | Wu, Yushu (Colorado School of Mines) | Peng, Yan (China university of Petroleum, Beijing)
Re-fracturing of a horizontal well is a method to restore the productivity of the well in unconventional reservoirs after the expected production decline. Consequently, a re-fracturing approach may be necessary to improve/enhance production and ultimate recovery. However, there are many challenges for optimizing re-fracturing treatment design, due to lack accurate quantification of depletion-induced pressure and local stress change around fractures. The workflow presented can be applied to study and optimize a re-fracturing job to prevent potentially catastrophic fracture hits during re-fracturing operations.
In this paper, an integrated re-fracturing workflow was created and applied to determine the optimum re-fracturing strategy for multi-wells pad. This comprehensive workflow represents a multidisciplinary approach that integrates complex hydraulic fracture models, geomechanical models, and multi-well production simulation. The approach is able to couple simulated 3D reservoir pressure with a geomechanical model to quantify depletion-induced stress and pressure field change. Then, the altered stress field is utilized as the input for modeling the new fracture system created by the re-fracturing treatment. Two field cases from a tight oil reservoir are evaluated by comparing the model prediction to the pressure response. The model prediction agrees well with the observed pressure response and surface tiltmeter observations. The synthetic cases of interference between wells due to stresses and fracture design (number, placement and timing) are investigated in this work. A systematic sensitivity study is performed on the effects of re-fracturing time, fracturing spacing.
It is shown that quantification of stress field changes during reservoir depletion provides new insights for the design and evaluation of re-fracturing treatments to enhance field development. There is a critical time in the life of the well that protection refrac could help pressurizing the formation directly by increasing pore pressure through fluid injection and indirectly by mechanical dilation of existing fractures. The dynamic changes of stress field can guide the optimization of re-fracturing mode and zipper fracturing to reduce stress shadow effect. The dynamic change of the pressure field optimizes the fracturing fluid volume, which can increases the volume of the fracture transformation and supply formation energy.
The paper presents aN approach in calculating stress changes and dynamic fracture propagation into depleted region over time. Results obtained by this study give better understanding about propagation of new fractures as well as old fractures in re-fracturing process.
Understanding the behavior of water-in-crude-oil emulsions is necessary to determine its effect on oil and gas production. The presence of emulsions in any part of the production system could cause many problems such as large pressure drop in pipelines due to its high viscosity. Electrical submersible pumps (ESPs) and gas lift are commonly used separately in lifting crude oil from wells. However, the use of downhole equipment and instruments such as ESPs that cause mixing can result in the formation of an emulsion with a high viscosity. The pressure required to lift emulsions is greater than the pressure required to lift non-emulsified liquids. Lifting an emulsion decreases the pressure drawdown capabilities, lowers production rate, increases the load on the equipment, shortens its life expectancy and can result in permanent equipment damage. Methods and apparatus which reduce the load on the pump, therefore, are desirable. The present paper is directed to understand the behavior of water-in-oil emulsions in artificial lift systems, mainly through gas lift.
Two stable water-in-oil synthetic emulsions were created in the laboratory and their rheology and stability characteristics were measured. One contained crude oil and the other, mineral oil. The second stage included measuring the effect of gas lift exposure on the emulsion behavior and characteristics. The results of the present work indicate that water-in-oil emulsions can be destabilized, and their viscosities lowered under gas exposure. The effect of gas injection on the emulsion was linked to the initial conditions of the emulsion as well as the gas type, injection rate and exposure time.
The present study is directed to methods and systems for combining both ESPs and gas lift for the purpose of improving and simplifying the lift of water-in-oil emulsions from oil wells. The novel methods and apparatus are based on the discovery that by adding gas above the ESPs in the wellbore, the viscosity of an oil-in-water emulsion is actually reduced, thus making it easier to lift oil from the well and extending the life of the ESP. Therefore, in addition to the normal benefits of gas in aiding the lift of liquids, if the gas lift valve is installed at a calculated distance above the pump location, the emulsion viscosity can be reduced. This reduces the load on the ESP.
The expansion of unconventional resources development has placed emphasis on better understanding of hydraulic fracturing stimulation effectiveness and the area of pay affected by the fracture treatment to optimize well spacing and improve completion and stimulation effectiveness. Existing fracture diagnostic methods such as microseismic monitoring and tiltmeters do not provide information about fracture connectivity to the wellbore. In this paper, we present a chemical tracer flowback based fracture diagnostic and analysis methods to estimate the fractional contribution of each created fracture stage, which is open and connected to the wellbore to help improve field development strategies and provide valuable information on optimal well paths for future drilling and development. The findings out from the stage production contribution profiles using the chemical tracer technology allows engineers to improve stimulation efficiency in multistage hydraulic fracturing horizontal wells applications for completion optimization and production enhancement. Two case histories are presented in which the chemical tracer technology was applied to two horizontal wells. The results of the chemical tracer analysis were correlated to production data, reservoir parameter and other diagnostic tests. The resultant findings from the analysis help evaluate completion and stimulation effectiveness and determine the extent of inter-well connectivity of the fracture network and then used to optimize future completions in the region.
This paper presents a data driven approach to answer the question of whether premium, high strength white sand proppant, while more expensive than regional (brown) sand, is justified due to its alleged ability to make better producing wells. For this study, 739 horizontal wells with production, and stimulation data were used in a robust statistical approach to conclude that, for the most common set of well characteristics, white sand will produce a superior NPV weighted economic outcome than lower cost regional (brown) sand alternatives. While there are wells in this analysis that did not produce this robust conclusion of "white sand is better", none of them produced an outcome that "brown sand was better". Rather, several of the wells simply had results that were statistically inconclusive. This paper serves as a good example of what data are needed to perform such an analysis and the challenges of normalizing'first order effects' that dominate the influence on well productivity (TVD, lateral length, and proppant intensity) while attempting to ascertain the influence of'second order' factors such as Sand Type. Becoming familiar and adept at these analysis methods should facilitate the statistical verification of other second order effects on finding the optimal stimulation treatment.
Ibrahim Mohamed, Mohamed (Colorado School of Mines) | Salah, Mohamed (Khalda Petroleum) | Coskuner, Yakup (Colorado School of Mines) | Ibrahim, Mazher (Apache Corp.) | Pieprzica, Chester (Apache Corp.) | Ozkan, Erdal (Colorado School of Mines)
A fracability model integrating the rock elastic properties, fracture toughness and confining pressure is presented in this paper. Tensile and compressive strength tests are conducted to define the rock-strength. Geomechanical rock properties derived from analysis of full-wave sonic logs and core samples are combined to develop models to verify the brittleness and fracability indices. An improved understanding of the brittleness and fracability indices and reservoir mechanical properties is offered and valuable insight into the optimization of completion and hydraulic fracturing design is provided. The process of screening hydraulic fracturing candidates, selecting desirable hydraulic fracturing intervals, and identifying sweet spots within each prospect reservoir are demonstrated.
Rosenhagen, Nicolas M. (Colorado School of Mines) | Nash, Steven D. (Anadarko Petroleum Corporation) | Dobbs, Walter C. (Anadarko Petroleum Corporation) | Tanner, Kevin V. (Anadarko Petroleum Corporation)
The volume of stimulation fluid injected during hydraulic fracturing is a key performance driver in the horizontal development of the Niobrara formation in the Denver-Julesburg (DJ) Basin, Colorado. Oil production per well generally increases with stimulation fluid volume. Often, operators normalize both production and fluid volume based on stimulated lateral length and investigate relationships using "per-ft" variables. However, data from well-based approaches commonly display such wide distributions that no useful relationships can be inferred. To improve data correlations, multivariate analysis normalizes for parameters such as thermal maturity, depth, depletion, proppant intensity, drawdown, geology and completion design. Although advancements in computing power have decreased cycle times for multivariate analysis, preparing a clean dataset for thousands of wells remains challenging. A proposed analytical method using publicly available data allows interpreters to see through the noise and find informative correlations.
Using a data set of over 5000 wells, we aggregate cumulative oil production and stimulation fluid volumes to a per-section basis then normalize by hydrocarbon pore volume (HCPV) per section. Dimensionless section-level Cumulative Oil versus Stimulation Fluid Plots ("Normalization" or "N-Plot") present data distributions sufficiently well-defined to provide an interpretation and design basis of well spacing and stimulation fluid volumes for multi-well development. When coupled with geologic characterization, the trends guide further refinement of development optimization and well performance predictions.
Two example applications using the N-Plot are introduced. The first involves construction of predictive production models and associated evaluation of alternative development scenarios with different combinations of well spacing and completion fluid intensity. The second involves "just-in-time" modification of fluid intensity for drilled but uncompleted wells (DUC's) to optimize cost-forward project economics in an evolving commodity price environment.
Srivastava, Vishal (Colorado School of Mines) | Majid, Ahmad A. A. (Colorado School of Mines) | Warrier, Pramod (Colorado School of Mines) | Grasso, Giovanny (Colorado School of Mines) | Koh, Carolyn A. (Colorado School of Mines) | Zerpa, Luis E. (Colorado School of Mines)
Gas hydrates are considered a major flow-assurance challenge in subsea flowlines. They agglomerate rapidly and form hydrate blockages. During transient operations [shut-in and restart (RS)], risk of blockage formation owing to hydrates can be greater compared to that during the continuous operations. In particular, hydrate formation during an unplanned shut-in and subsequent restart could lead to increased operational hazards. In this work, flow-loop tests were conducted under both continuous-pumping (CP) and RS conditions, using Conroe crude oil with three different water fractions (30, 50, 90 vol%) at 5 wt% salinity, over a range of mixture velocities (from 2.4 to 9.4 ft/sec). It was determined that RS operations resulted in an earlier onset of hydrate particle bedding—twice as fast as those in CP tests—from the interpretation of pressure-drop and mass-flow-rate (MFR) measurements. Droplet imaging using a particle vision and measurement (PVM) probe suggested larger water droplets (100–300 µm) during the shut-in, as compared to the CP tests (=40 µm) at 50 and 90 vol% water cuts (WCs). For the tests performed using a demulsifier at 200 ppm, PVM images suggested larger water droplets (mean droplet size = 94 µm), as compared with the test with no demulsifier (mean droplet size = 21 µm). The test using a demulsifier resulted in higher pressure drops and lower MFRs compared with the test with no demulsifier, indicating poor hydrate transportability when water was partially dispersed in the oil phase. The current study indicated that partially dispersed systems present greater risks of hydrate plugging as compared with the fully dispersed systems in the range of water volume fractions from 50 to 95 vol% WC, which was the phase inversion point of the water-in-crude-oil (Conroe14 crude) system. The flow-loop-test analyses presented in this work can potentially aid in an improved mechanistic understanding of RS operations, involving unplanned shut-ins and restarts.
Tian, Ye (Colorado School of Mines) | Xiong, Yi (Colorado School of Mines) | Wang, Lei (Colorado School of Mines) | Lei, Zhengdong (Research Institute of Petroleum Exploration and Development, PetroChina) | Zhang, Yuan (Research Institute of Petroleum Exploration and Development, PetroChina) | Yin, Xiaolong (Colorado School of Mines) | Wu, Yu-Shu (Colorado School of Mines)
Gas injection has become the top choice for IOR/EOR pilots in tight oil reservoirs because of its high injectivity. The effects of nanoconfinement and geomechanics are generally considered as non-negligible, but its coupled effects and resulting flow and displacement are still not well understood for gas injection. We hence present a general compositional model and simulator to investigate the complicated multiphase and multicomponent behaviors during gas injection in tight oil reservoirs.
This compositional model is able to account for vital physics in unconventional reservoirs, including nanopore confinement, molecular diffusion, rock-compaction, and non-Darcy flow. The MINC method is implemented to handle fractured media. The nanopore confinement effect is modeled by including capillarity in VLE calculations. The rock compaction effect is represented by solving the mean stress from a governing geomechanical equation which is fully coupled with the mass balance equations to ensure the numerical stability as well as a physically correct solution. The equations are discretized with integral finite difference method and then solved numerically by Newton's method.
The simulator is validated against a commercial compositional software (CMG-GEM) before it is applied to simulate gas injection. Huff-n-puff with dry gas in Eagle Ford is investigated. The simulation result shows that if the reservoir pressure is much higher than the bubble point pressure, the nanopore confinement effect will have a minimal impact on the recovery factor (RF) for both the depletion and the first few cycles of gas huff-n-puff. Geomechanics is found to be an influencing factor on RF but not always in a detrimental way, as enhanced rock compaction drive could offset the reduction of permeability in certain scenarios. Gas huff-n-puff would improve the RF of each component compared with the depletion. The heavy component would first have a higher recovery than the light component at the first few cycles of huff-n-puff, but its RF will be outpaced by the light component when the gas saturation in the matrix surpasses the critical gas saturation. Lastly, considering the nanopore confinement effects would slightly reduce the RF of the light component but increase the RF of the heavy component after huff-n-puff when combined with the critical gas saturation effect in the matrix.
This study presents a 3D multiphase, multicomponent simulator which is a practical tool for accurately modeling of primary depletion as well as gas injection IOR/EOR processes in unconventional oil reservoirs. This simulator is not only of great importance for assisting researchers to understand complex multiphase and multicomponent behaviors in tight oil production but also of great use for engineers to optimize gas injection parameters in field applications.
In this work, we present the development of a compositional simulator accelerated by proxy flash calculation. We aim to speed up the compositional modeling of unconventional formations by stochastic training.
We first developed a standalone vapor-liquid flash calculation module with the consideration of capillary pressure and shift of critical properties induced by confinement. We then developed a fully connected network with 3 hidden layers using Keras. The network is trained with Adam optimizer. 250,000 samples are used as training data, while 50,000 samples are used as testing data. Based on the trained network, we developed a forward modeling (prediction) module in a compositional simulator. Therefore, during the simulation run, the phase behavior of the multicomponent system within each grid block at each iteration is obtained by simple interpolation from the forward module.
Our standalone flash calculation module matches molecular simulation results well. The accuracy of the trained network is up to 97%. With the implementation of the proxy flash calculation module, the CPU time is reduced by more than 30%. In the compositional simulator, less than 2% of CPU time is spent in the proxy flash calculation.
The novelty of this work lies in two aspects. We have incorporated the impacts of both capillary pressure and shift of critical properties in the flash calculation, which matches molecular simulation results well. We developed a proxy flash calculation module and implemented it in a compositional simulator to replace the traditional flash calculation module, speeding the simulation by 30%.
Tight oil and shale gas reservoirs have a significant part of their pore volume occupied by micro (below 2nm) and mesopores (between 2 and 50nm). This kind of environment creates strong interactions forces in the confined fluid with pore walls as well as between its own molecules and then changes dramatically the fluid phase behavior and its thermodynamic properties. Pressure-Vapor-Temperature (