Wang, Bin (University of Louisiana, Lafayette) | Feng, Yin (University of Louisiana, Lafayette) | Du, Juan (China National Offshore Oil Corporation) | Wang, Yihui (University of Louisiana, Lafayette) | Wang, Sijie (University of Louisiana, Lafayette) | Yang, Ruiyue (China University of Petroleum, Beijing)
Reactive-transport phenomena, such as carbon dioxide sequestration and microbial enhanced oil recovery (EOR), have been of interest in streamline-based simulation (SLS). Tracing streamlines launched from a wellbore is important, especially for time-sensitive transport behaviors. However, discretized gridblocks are usually too large compared with the wellbore radius. Field-scale simulations with local-grid-refinement (LGR) models often consume huge computational time. An embedded grid-free approach to integrate near-wellbore transport behaviors into streamline simulations is developed, comprising two stages of development: tracing streamlines in a wellblock (a gridblock containing wells) and coupling streamlines with neighboring grids. The velocity field in a wellblock is produced using a gridless virtual-boundary-element method (VBEM), where streamlines are numerically traced with the fourth-order Runge-Kutta (RK4) method (Butcher 2008). The local streamline system is then connected with the global streamline system, which is produced with the Pollock (1988) algorithm. Finally, the reactive-transport equation will be solved along these streamlines.
The algorithm presented for solving near-wellbore streamlines is verified by both a commercial finite-element simulator and a Pollock-algorithm-based 3D streamline simulator. A series of computational cases of reactive-transport simulation is studied to demonstrate the applicability, accuracy, and efficiency of the proposed method. Velocity field, time-of-flight (TOF), streamline pattern, and concentration distribution produced by different approaches are analyzed. Results show that the presented method can accurately perform near-wellbore streamline simulations in a time-effective manner. The algorithm can be directly applied to one grid containing multiple wells or to off-center wells. Furthermore, assuming streamlines are evenly launched from the gridblock boundary or ignoring transport in the wellblock is not always reasonable, and may lead to a significant error.
This study provides a simple and grid-free solution, but is capable of capturing the flow field near the wellbore with significant accuracy and computational efficiency. The method is promising for reservoir SLS with time-sensitive transport, and other simulations requiring an accurate assessment of interactions between wells in one particular gridblock.
Wang, Haitao (Petroleum Exploration & Production Research Institute, Sinopec) | Lun, Zengmin (Petroleum Exploration & Production Research Institute, Sinopec) | Lv, Chengyuan (Petroleum Exploration & Production Research Institute, Sinopec) | Lang, Dongjiang (Petroleum Exploration & Production Research Institute, Sinopec) | Pan, Weiyi (Petroleum Exploration & Production Research Institute, Sinopec) | Luo, Ming (Petroleum Exploration & Production Research Institute, Sinopec) | Wang, Rui (Petroleum Exploration & Production Research Institute, Sinopec) | Chen, Shaohua (Petroleum Exploration & Production Research Institute, Sinopec)
Nuclear magnetic resonance (NMR) was used to investigate the exposure between carbon dioxide (CO2) and the sandstone matrix with a permeability of 0.218 md and a porosity of 9.5% at 40°C and 12 MPa (immiscible condition). Minimum miscibility pressure (MMP) between oil and CO2 was 17.8 MPa, determined by slimtube test at 40°C. The exposure process between CO2 and the sandstone matrix included first, second, third, and fourth exposure experiments. Before each exposure experiment started, there was a CO2-injection stage with a CO2 injection under a constant pressure of 12 MPa and at a constant rate to keep fresh CO2 (concentration of CO2 is 100% in gas phase) in the system. Each exposure experiment ended when the obtained T2 spectrum was unchanged (total amount of oil in tight matrix remains constant). These processes were similar to CO2 huff 'n' puff. The results showed that (1) oil in all pores could mobilize as exposure time increases in the first exposure experiment. (2) The total original-oil-in-place (OOIP) recovery is 46.6% for oil in big pores (29 ms < T2 <= 645 ms)—this result is higher than the recovery (12.8%) for oil in small pores (T2 <= 29 ms). (3) Oil is mobilized fast in the initial exposure hours, and then the rate drops gradually until no more oil is produced. (4) Initially, the oil exists in pores with maximum relaxation times of 645 ms in the originally saturated core. After the CO2 injection, oil flows to pores with relaxation times slower than 645 ms, suggesting that oil in tight matrix is mobilized to the surface of core by swelling caused by CO2 diffusion. (5) The final OOIP recoveries of first, second, third, and fourth exposure experiments are 23.7, 7.2, 2.6, and 1.5%, respectively, and they decline exponentially. Oil mobilization in a tight-sandstone reservoir exposed to CO2 was observed by NMR T2 spectra under multiple exposure experiments. Mechanisms of oil mobilization were investigated (i.e., oil swelling, concentration-driven diffusion of hydrocarbons, and extraction of light components). The CO2 enhanced oil recovery (EOR) with multiple injections under immiscible conditions is acceptable and satisfactory in a tight-sandstone reservoir. CO2 huff 'n' puff with optimized injection, soaking, and production process is an economic development method in a tight sandstone reservoir.
Padin, Anton (Colorado School of Mines) | Torcuk, Mehmet A. (EOG Resources) | Katsuki, Daisuke (Colorado School of Mines) | Kazemi, Hossein (Colorado School of Mines) | Tutuncu, Azra N. (Colorado School of Mines)
The objective of this research is to determine the physicochemical processes underlying water and solute transport in organic-rich source rocks. To achieve this goal, a custom-designed experimental apparatus was constructed to conduct flow tests, founded on a high-pressure triaxial assembly. The apparatus is capable of maintaining core samples at reservoir pressure, temperature, and confining stress. We conducted several 120-day low-salinity osmotic tests in low-clay, organic-rich Eagle Ford carbonate-shale samples. Test results showed gradual, slow increase of pressure within the samples. Because this pressure behavior could not be explained properly with classical models, we formulated a mass-transport mathematical model that relies on fundamental chemical osmosis principles driving low-salinity brine into high-salinity core samples.
Our mathematical model was articulated to simulate flow into the core as a 3D porous medium rather than transport across a thin, molecule-selective membrane. The model is dependent on the following principles: The low-salinity brine selectively enters the pores by diffusion mass transport, and the pre-existing, ionized dissolved salt molecules within the core are restrained by internal electrostatic forces to counterdiffuse in the direction opposite to that of the low-salinity-brine molecules entering the pore network. Critical model input data, such as permeability, porosity, and rock compressibility, were obtained from flow experiments on twin cores, and the diffusion coefficient was chosen by history matching. The strengths of the numerical simulation include reliance on mass-transport fundamental principles; not requiring the use of an ambiguously defined membrane-efficiency term; and relying on chemical-potential gradient as the driving force for the low-salinity brine to enter the high-salinity core, generating osmotic pressure within the pore network. The latter implies that osmotic pressure is the consequence of water entering the cores, not the cause. Results of this research have provided a more plausible explanation of pore-scale mass transport in organic-rich shales, and provide useful insights for design of effective enhanced-oil-recovery (EOR) processes.
Majid, Ahmad A. A. (Colorado School of Mines and Universiti Malaysia Pahang) | Lee, Wonhee (Colorado School of Mines) | Srivastava, Vishal (Colorado School of Mines) | Chen, Litao (Colorado School of Mines) | Warrier, Pramod (Colorado School of Mines) | Grasso, Giovanny (Colorado School of Mines) | Vijayamohan, Prithvi (Colorado School of Mines) | Chaudhari, Piyush (Colorado School of Mines) | Sloan, E. Dendy (Colorado School of Mines) | Koh, Carolyn A. (Colorado School of Mines) | Zerpa, Luis (Colorado School of Mines)
As the oil-and-gas industries strive for better gas-hydrate-management methods, there is the need for improved understanding of hydrate formation and plugging tendencies in multiphase flow. In this work, an industrial-scale high-pressure flow loop was used to investigate gas-hydrate formation and hydrate-slurry properties at different flow conditions: fully dispersed and partially dispersed systems. It has been shown that hydrate formation in a partially dispersed system can be more problematic compared with that in a fully dispersed system. For hydrate formation in a partially dispersed system, it was observed that there was a significant increase in pressure drop with increasing hydrate-volume fraction. This is in contrast to a fully dispersed system in which there is gradual increase in the pressure drop of the system. Further, for a partially dispersed system, studies have suggested that there may be hydrate-film growth at the pipe wall. This film growth reduces the pipeline diameter, creating a hydrate bed that then leads to flowline plugging. Because there are different hydrate-formation and -plugging mechanisms for fully and partially dispersed systems, it is necessary to investigate and compare systematically the mechanism for both systems. In this work, all experiments were specifically designed to mimic the flow systems that can be found in actual oil-and-gas flowlines (full and partial dispersion) and to understand the transportability of hydrate particles in both systems. Two variables were investigated in this work: amount of water [water cut (WC)] and pump speed (fluid-mixture velocity). Three different WCs were investigated: 30, 50, and 90 vol%. Similarly, three different pump speeds were investigated: 0.9, 1.9, and 3.0 m/s. The results from these measurements were analyzed in terms of relative pressure drop (∆Prel) and hydrate-volume fraction (ϕhyd). It was observed that, for all WCs investigated in this work, the ∆Prel decreases with increasing pump speed, at a similar hydrate-volume fraction. Analysis conducted with the partially-visual-microscope (PVM) data collected showed that, at constant WC, the hydrate-particle size at the end of the tests decreases as the mixture velocity increases. This indicates that the hydrate-agglomeration phenomenon is more severe at low mixture velocity. Calculations of the average hydrate-growth rate for all tests conducted show that the growth rate is much lower at a mixture velocity of 3.0 m/s. This is attributed to the heat generated by the pump. At a high mixing speed of 3.0 m/s, the pump generated a significant amount of heat that then increased the temperature of the fluid. Consequently, the hydrate-growth rate decreases. It should be stated that this warming effect should not occur in the field. Flow-loop plugging occurred for tests with 50-vol% WC and pump speeds lower than 1.9 m/s, and for tests with 90-vol% WC at a pump speed of 0.9 m/s. In addition, in all 90-vol%-WC tests, emulsion breaking, where the two phases (oil and water) separated, was observed after hydrate formation. From the results and observations obtained from this investigation, proposed mechanisms are given for hydrate plugging at the different flow conditions. These new findings are important to provide qualitative and quantitative understanding of the key phenomena leading to hydrate plugging in oil/gas flowlines.
Cai, Quan (Texas A&M University) | Yu, Wei (Texas A&M University) | Liang, Hwa Chi (Texas A&M University) | Liang, Jenn-Tai (Texas A&M University) | Wang, Suojin (Texas A&M University) | Wu, Kan (Texas A&M University)
The oil-and-gas industry is entering an era of “big data” because of the huge number of wells drilled with the rapid development of unconventional oil-and-gas reservoirs during the past decade. The massive amount of data generated presents a great opportunity for the industry to use data-analysis tools to help make informed decisions. The main challenge is the lack of the application of effective and efficient data-analysis tools to analyze and extract useful information for the decision-making process from the enormous amount of data available. In developing tight shale reservoirs, it is critical to have an optimal drilling strategy, thereby minimizing the risk of drilling in areas that would result in low-yield wells. The objective of this study is to develop an effective data-analysis tool capable of dealing with big and complicated data sets to identify hot zones in tight shale reservoirs with the potential to yield highly productive wells. The proposed tool is developed on the basis of nonparametric smoothing models, which are superior to the traditional multiple-linear-regression (MLR) models in both the predictive power and the ability to deal with nonlinear, higher-order variable interactions. This data-analysis tool is capable of handling one response variable and multiple predictor variables. To validate our tool, we used two real data sets—one with 249 tight oil horizontal wells from the Middle Bakken and the other with 2,064 shale gas horizontal wells from the Marcellus Shale. Results from the two case studies revealed that our tool not only can achieve much better predictive power than the traditional MLR models on identifying hot zones in the tight shale reservoirs but also can provide guidance on developing the optimal drilling and completion strategies (e.g., well length and depth, amount of proppant and water injected). By comparing results from the two data sets, we found that our tool can achieve model performance with the big data set (2,064 Marcellus wells) with only four predictor variables that is similar to that with the small data set (249 Bakken wells) with six predictor variables. This implies that, for big data sets, even with a limited number of available predictor variables, our tool can still be very effective in identifying hot zones that would yield highly productive wells. The data sets that we have access to in this study contain very limited completion, geological, and petrophysical information. Results from this study clearly demonstrated that the data-analysis tool is certainly powerful and flexible enough to take advantage of any additional engineering and geology data to allow the operators to gain insights on the impact of these factors on well performance.
Zhao, Dapeng (Norwegian University of Science and Technology and SINTEF) | Hovda, Sigve (Norwegian University of Science and Technology) | Sangesland, Sigbjørn (Norwegian University of Science and Technology)
Most drill-collar-connection failures are attributed to cumulative fatigue caused by bending vibration. An important class of bending vibration is whirl, which is formed by the eccentricity of the rotational drill collar. The contact between the drill collar and the borehole causes extreme harmful backward whirl, even chaotic whirl. A two-degree-of-freedom nonlinear lumped-mass model is used to represent the drill collar in whirl. Unlike other studies, the stick/slip vibration causing fluctuation of rotary speed is taken into account. In this lumped-element model, the contact forces obey the Hertzian contact law, which leads to lateral bounce of the drill collar and affects the borehole wall chaotically. The modified Karnopp friction model is adopted to simulate the stick/slip rotary vibration of the bottomhole assembly (BHA). On the basis of the time-domain responses of whirl, the continuous-bending-stress history is broken down into individual stress ranges with an associated number of stress cycles using the rainflow-counting method. The cumulative fatigue damage is estimated using Miner’s rule. The conclusion of this paper indicates that chaotic lateral vibration and fatigue damage happen at a lower rotational speed than previously reported.
Economic production from shale-gas reservoirs typically relies on the drilling of horizontal wells and hydraulic fracturing in multiple stages. In addition to the creation of hydraulic fractures, hydraulic-fracturing treatment can also reopen existing natural fractures, which can create a complex-fracture network. The area that is covered by the fracture network is usually termed the stimulated reservoir volume (SRV), and the spatial extent and properties of the SRV are crucial for shale-gas-production behavior. In this work, we propose a method for history matching of the SRV of shale-gas reservoirs using production data. For each hydraulic-fracturing stage, the fracture network is parameterized with one major fracture of the hydraulic fractures and the SRV that represents minor hydraulic fractures and reopened natural fractures. The major fracture is modeled explicitly, whereas the SRV is modeled by the dual-permeability/dual-porosity (DP/DP) model. Moreover, the spatial extent of the SRV is parameterized by the level-set-function values on a predefined representing-node system. After parameterization, an iterative ensemble smoother is used to perform history matching. Both single-stage-fracturing cases and multistage-fracturing cases are set up to test the performance of the proposed method. Numerical results demonstrate that by use of the proposed method, the SRV can be well-recognized by assimilating production data.
Xiao, Cong (China University of Petroleum, Beijing and Delft University of Technology) | Dai, Yu (CNPC) | Tian, Leng (China University of Petroleum, Beijing) | Lin, Haixiang (Delft University of Technology) | Zhang, Yayun (China University of Petroleum, Beijing) | Yang, Yaokun (China University of Petroleum, Beijing) | Hou, Tengfei (China University of Petroleum, Beijing) | Deng, Ya (CNPC)
Recently, a multiwell-pad-production (MWPP) scheme has been the center of attention as a promising technology to improve shale-gas (SG) recovery. However, the increasing possibility of multiwell pressure interference (MWPI) in the MWPP scheme severely distorts flow regimes, which strongly challenges the traditional pressure-transient analysis methods that focus on single multifractured horizontal wells (SMFHWs) without MWPI. Therefore, a methodology to identify pressure-transient response of the MWPP scheme with and without MWPI is urgent. To fill this gap, a new semianalytical pressure-transient model of the MWPP scheme is established by use of superposition theory, Gauss elimination, and the Stehfest numerical algorithm. Type curves are generated, and flow regimes are identified by considering MWPI. Finally, a sensitivity analysis is conducted.
Our results show that there are good agreements between our proposed model and numerical simulation; moreover, our semianalytical approach also demonstrates a promising calculation speed compared with numerical simulation. Some expected flow regimes are significantly distorted by MWPI. In addition, well rate determines the distortion of pressure curves, whereas fracture length, well spacing, and fracture spacing determine when the MWPI occurs. The smaller the gas rate, the more severely flow regimes are distorted. As the well spacing increases, fracture length decreases, fracture spacing decreases, and the occurrence of MWPI occurs later. The stress-sensitivity coefficient has little to no influence on the occurrence of MWPI. Similar to the concept of the dual-porosity model, three new flow regimes—the single-well flow regime, MWPI flow regime, and MWPP flow regime—are artificially defined to systematically characterize the flow regimes of the MWPP scheme.
This work offers some additional insights on pressure-transient response for the MWPP scheme in the SG reservoir, which can provide considerable guidance for fracture-properties estimation and well-pattern optimization for the MWPP scheme.
Wang, Zhibin (Southwest Petroleum University and Xi'an Jiaotong University) | Guo, Liejin (Xi'an Jiaotong University) | Zhu, Suyang (Southwest Petroleum University) | Nydal, Ole Jørgen (Norwegian University of Science and Technology)
Analysis of the experimental data for liquid-entrainment rate, forces exerted on liquid droplet, and secondary flow occurring in the gas core show that the liquid is mainly carried in the form of film in the inclined annular flow. Therefore, it is more reasonable to establish a mathematical model from the bottom-film reversal than from the droplet reversal.
In this study, a new analytical model is developed from force balance of the bottom film of the inclined tubing after studying the bottom-film thickness and gas/liquid interfacial friction factor to reveal the liquid-loading mechanism. Furthermore, a new Belfroid-like empirical model is proposed that is based on the calculation results of a wide range of flowing parameters from the new analytical model to predict the liquid-loading status of gas wells. The new empirical model introduces a coefficient Cd,p,uSL,T to consider how the fluid properties under downhole flow condition affect the critical gas velocity. Cd,p,uSL,T in the new empirical model increases with the pipe diameter, liquid velocity, and flowing pressure, and decreases with the flowing temperature.
The new analytical model, having an average error of 8.45%, agrees well with the published experimental data, and it also performs well in predicting the pressure gradient at liquid unloading condition. The new empirical model could be applied for the prediction of real field operations and has been validated with an accuracy rate of 95% against data newly collected from 60 horizontal wells. The new work can accurately and easily judge the liquid-loading status, and it also reveals how the fluid properties under downhole flowing condition affect the liquid loading.
The conventional method for multiphase flash is the sequential usage of phase-stability and phase-split calculations. Multiphase flash requires the conventional method to obtain multiple false solutions in phase-split calculations and correct them in phase-stability analysis. Improvement of the robustness and efficiency of multiphase flash is important for compositional flow simulation with complex phase behavior.
This paper presents a new algorithm that solves for stationary points of the tangent-plane-distance (TPD) function defined at an equilibrium-phase composition for isobaric-isothermal (PT) flash. A solution from the new algorithm consists of two groups of stationary points: tangent and nontangent stationary points of the TPD function. Hence, equilibrium phases, at which the Gibbs free energy is tangent to the TPD function, are found as a subset of the solution.
Unlike the conventional method, the new algorithm does not require finding false solutions for robust multiphase flash. The advantage of the new algorithm in terms of robustness is more pronounced for more-complex phase behavior, for which multiple local minima of the Gibbs free energy are present. Case studies show that the new algorithm converges to a lower Gibbs free energy compared with the conventional method for the complex fluids tested. It is straightforward to implement the algorithm because of the simple formulation, which also allows for an arbitrary number of iterative compositions. It can be robustly initialized even when no K value correlation is available for the fluid of interest. Although the main focus of this paper is on robust solution of multiphase flash, the new algorithm can be used to initialize a second-order convergent method in the vicinity of a solution.