To improve magnetic disturbance rejection and robustness of wellbore survey measurements, an adaptive neuro network-based fuzzy inference system (ANFIS) filter for wellbore position calculation is presented. This technique significantly improves magnetic disturbance rejection and reduces sensor error influence for borehole survey measurements. The new approach for the ANFIS filter is based on two redundant sets of IMUs which are located in different positions in the BHA at a known, constant distance. The distance between these two sets of IMUs will physically fade the effect of the magnetic disturbances. Each IMU set outputs position estimation based on the splines method which is then input into an ANFIS filter. The inputs of the splines calculation are azimuth, inclination angles and measurement depth, and the outputs are moving distance in three directions (Northing, Easting and True Vertical Depth). However, the accuracy of the splines method highly depends on the accuracy of the inputs, which are difficult to obtain during the measurement while drilling process even under pure clean environments (without any magnetic disturbances). Furthermore, the distorted azimuth caused by magnetic interference affects the borehole position accuracy. In order to deal with those problems, the designed ANFIS filter has a two-level structure. First a local level position estimation (splines method or well trained local ANFIS based on the sensor accuracy) for two sensor sets is used. If the sensor measurement accuracy is low, this local ANFIS will correct the position estimation. Then the outputs of the local modules were input into ANFIS for second level filtering (global filter) to remove the error which caused by unknown magnetic disturbances. According to the judgement of the ANFIS, the IMU set with the smaller magnetic disturbance is given greater weight to reduce the interference effect on the borehole position estimation. This two-level filter is compared to the traditional splines method under different tests situations. First, we evaluate this method by comparing with GPS positioning, from this test we know that the ANFIS filter shows a good performance when the magnitude of magnetic disturbance is within the training magnitude range. Even when the magnitude of magnetic disturbance is above the training range, the ANFIS filter shows a higher robustness than the traditional splines method. Also, this method was applied to borehole data with two IMU containing accelerometers and one magnetometer measurements. In order to apply our method, we duplicated one more magnetometer measurement data under magnetic interference for assessment. The results proved its magnetic disturbance robustness in borehole position estimation. Finally, we demonstrate the full potential using a laboratory experimental setup.
Pastusek, Paul (ExxonMobil Development Co.) | Payette, Greg (ExxonMobil Upstream Research Co.) | Shor, Roman (University of Calgary) | Cayeux, Eric (Norce) | Aarsnes, Ulf Jakob (Norce) | Hedengren, John (Brigham Young University) | Menand, Stéphane (DrillScan) | Macpherson, John (Baker Hughes GE) | Gandikota, Raju (MindMesh Inc.) | Behounek, Michael (Apache Corp.) | Harmer, Richard (Schlumberger) | Detournay, Emmanuel (University of Minnesota) | Illerhaus, Roland (Integrity Directional) | Liu, Yu (Shell Development Co.)
The drilling industry has substantially improved performance based on knowledge from physics-based, statistical, and empirical models of components and systems. However, most models and source code have been recreated multiple times, which requires significant effort and energy with little additional benefit or stepwise improvements. The authors propose that it is time to form a coalition of industry and academic leaders to support an open source effort for drilling, to encourage the reuse of continuously improving models and coding efforts. The vision for this guiding coalition is to 1) set up a repository for source code, data, benchmarks, and documentation, 2) encourage good coding practices, 3) review and comment on the models and data submitted, 4) test, use and improve the code, 5) propose and collect anonymized real data, 6) attract talent and support to the effort, and 7) mentor those getting started. Those interested to add their time and talent to the cause may publish their results through peer-reviewed literature.
Unconventional reservoirs, especially shale gas reservoirs, exhibit dual porosity (free fluid porosity and adsorbed fluid porosity). The adsorbed volume is a function of total organic carbon (TOC) and thus, higher organic contents are assumed to be directly related to higher hydrocarbons in place. However, this case study tried to evaluate this concept and found that with higher TOC, though gas in place increases the recoverable hydrocarbons reduces due to the low contribution from adsorbed heavier components.
We thoroughly evaluate the impact of organic contents on adsorbed hydrocarbons and further compare with the petrophysical properties and production behaviors; herein using information from the Devonian aged Duvernay Formation in Western Canada. First, multi-well analysis of core and log-derived TOC revealed that variations in organic contents are a function of the stratigraphy and thermal maturity, particularly increases in carbonate contents seems to correlate with lower organic contents, whereas increases in quartz and clays correlate with higher organic contents. Then, adsorption capacities were analyzed as a function of variations in the TOC. Finally, comparisons of hydrocarbons in-place and production contribution of the adsorbed volume is analyzed for different average TOC wells.
It is observed that TOC impacts relative adsorption of methane which further impacts the fluid characteristics (gas wells have higher average TOC as compared to the oil wells). This observation becomes relevant as we could partially understand well performance from fundamental understandings of the variations in organic contents. Results of Langmuir isotherms indicate a significant increase in adsorption of heavier components compared to the increment in adsorption of methane components with higher TOC. This observation is further analyzed for production data of the multi-fractured horizontal wells which suggested the following: 1) desorption in the oil flowing wells increases as the saturation of the oil phase decreases, or in other words when the relative permeability of the gas increases. 2) In the gas flowing wells, desorption does not follow the trend of the relative permeability, while based on Langmuir pressure initial contribution is significant which declines as reservoir pressure drops. Further, for the gas flowing well, the production forecast from calibrated production model (with measured produced volumes) shows that post-production of 10 years, recovery is 3.66% in which contribution from desorption is about 17.6%. This observation in the production analyses highlights how with different adsorption capacities of heavier components, adsorption contribution in the production varies. Finally, post this study it is found that TOC plays a vital role in adsorption capacity, gas in place and in the production performance. The relation of the TOC with fluid characterization and recoverable reserves is complex and should be analyzed with the variation in adsorption and desorption capacity of lighter and heavier components.
Dependency of relative permeability on saturation path during cyclic CO2 injection (CCI) in various operational constraints affects the oil recovery in different ways. A compositional reservoir sector model is built based on the available production data of hydraulically fractured horizontal well in Bakken formation. The work discusses the simulation results of the CCI and investigates the contributions of non-wetting phase's relative permeability hysteresis in oil production below and above the minimum miscibility pressure (MMP).
A CMG-GEM model is built based on the Bakken geological settings, well production and live oil PVT data. Relative permeability hysteresis model is incorporated within the simulator using the Killough's method. A cyclic CO2 injection (CCI) EOR scheme is designed and implemented in the numerical model. Effects of structural trapping and hysteresis-induced CO2 /gas retardation on oil recovery are studied during CCI in which a strong flow reversals may occur.
The results of simulation revealed that in non-hysteretic model, performing cyclic CO2 injection at immiscible (2000psi) and miscible (5000psi) conditions increases the recovery up to 12.8% and 22.64% respectively. Recovered oil after inclusion of relative permeability hysteresis demonstrate major corresponding effects of gas retardation, CO2 trapping and improved water permeability. The results show mole fraction of CO2 invading the reservoir remains constant at miscible condition and is not affected by hysteresis. Yet in hysteretic model, the oil recovery factor is slightly declined as the relative permeability to water is improved. The immiscible-hysteretic model incorporates high residual gas/ CO2 gas saturation at the end of each production (imbibition) cycle which increases gradually with historical gas saturation. CO2 mole fractions in both gas and oil phases are intensely decreased due to hysteresis following by decline in CO2 injectivity. Residual CO2 trapped during early cycles, limits the CO2 extent in reservoir and makes the recovery less efficient. In addition to residual saturation, oil composition varies due to different rates of vaporization and diffusion by CO2 as a result of its uneven distribution in reservoir.
We accurately evaluated the efficiency of cyclic CO2 injection in to Bakken tight oil reservoir by incorporating gas-trapping mechanisms in the model. Shortcomings of uncertainties associated with the previous simplified non-hysteretic reservoir models is reduced. Various operational conditions are tested. Our results draw a distinction amongst underlying mechanisms of recovery induced by hysteresis at different miscibility conditions.
Kim, Jeong Woo (University of Calgary) | Rangelova, Elena (University of Calgary) | Kabirzadeh, Hojjat (University of Calgary) | Lee, Gyoo Ho (Korea Gas Corporation) | Jeong, Jaehoon (Al Dhafra Petroleum Operations Co.) | Woo, Ik (Kunsan National University) | Song, Tae Han (Korea Gas Corporation)
Safe and economical determination of wellpath in directional drilling is traditionally achieved by the measurement-while-drilling (MWD) method which implements geopotential sensors, i.e., magnetometers and accelerometers. However, inaccuracies in determination of the wellpath arise because of random and systematic errors in measurements. In general, inclination is under good control with gravity measured by accelerometer, while azimuth requires a number of corrections as it also requires magnetic measurement which involves multiple sources of errors such as sensor errors, poorly-modelled crustal magnetic variation, drillstring magnetization, etc. These errors must be completely reduced or minimized to obtain an accurate wellbore position. A magnetic-free system and method to determine a borehole azimuth in the directional drilling is investigated in this study. We show that a borehole azimuth can be properly determined by using a system of coupled accelerometers mounted on measurement-while-drilling (MWD) sensors using Gravity in-Field Referencing (GiFR). In order to reduce errors due to relative oritation of the coupled drillstrings, we developed the Quaternion-based GiRF which considers the relative diaplacements and rotations between the two sets of accelerometer resulting in determining an improved azimuth.
Relative permeability curves in coalbed methane reservoirs (CBM), acquired by analysis of production data, can differ from laboratory-measured curves due to complications such as stress-desorption dependent permeability and cross-formational flow. This paper aims to derive relative permeability curves for coalbed methane reservoirs using production data analysis, as well as discuss curve characteristics and shapes. Field examples from the San Juan Basin in the US and the Qinshui and Ordos Basins in China are presented to provide a worldwide view of relative permeability curve shapes. These field examples are analysed using a tank type model, a common production data analysis tool, and the influential factors on curve shapes are discussed. The results and analysis indicate that permeability enhancement during the life of the well, and cross-formational flow between the coal seam and adjacent formations, can strongly control curve shapes. These effects, when not detected, can result in irregular relative permeability curve shapes obtained by analysis of production data. Direct measurement of permeability enhancement requires time-lapse production tests while investigation of cross-formational flow of water into coal seams requires hydraulic connectivity assessment, which are time consuming and expensive to conduct. The signatures of relative permeability curves presented in this study allow indirect determination of permeability enhancement and cross-formational flow in coal seam gas reservoirs.
Nanoparticle stabilized emulsions have drawn increasing attention for applications in various industries including enhanced oil recovery (EOR). Unlike surfactants, nanoparticles provide long-term stability to the emulsions and significantly higher viscoelastic response. However, the flow behavior of nanoparticle stabilized emulsions in porous media has not been explored much. Cellulose Nanocrystals (CNCs) have gained attention in the past few years since they are an abundant renewable biomass-derived material. This study investigates the flow behavior and stability of oil in water emulsions stabilized by CNCs in unconsolidated porous media and the application of these emulsions in EOR and conformance control.
Confocal Microscopy coupled with Cryo-SEM enabled us to precisely characterize the emulsion microstructure and correlate it to the rheological behavior of the emulsions. The rheological measurements revealed that a strong droplet network forms within the emulsions over time. Importantly, we show that the same network forms when the emulsions occupy pore space in a granular material. Emulsions were injected through a sandpack with a porosity of 35% and average pore diameter of 54 μm. The injected emulsions were aged inside the porous media for 24 hours. Thorough experimental assessment of the collected effluent samples revealed that the emulsion was stable. The porous medium was then subjected to a gradually increasing pressure gradient of either water or oil. Gradients greatly exceeding typical near-well values (>300 psi/ft) were required to establish flow, and the resulting flow rate exhibited a pressure gradient three orders of magnitude higher than in an untreated water saturated sandpack. Interestingly, a significantly larger gradient was needed for water to flow than for oil, raising the possibility of using this class of emulsions for selective phase blocking, and perhaps as relative permeability modifiers. Moreover, emulsions stabilized with other material allowed water to flow at very small gradients, confirming that the network formation is critical for this application.
This study revealed the potential application of a naturally occurring biodegradable nanomaterial for conformance control and for curbing excessive water production where zonal isolation is difficult to achieve.
In recent years, the Cyclic Solvent Injection (CSI) process has shown to be a promising method for enhanced heavy oil recovery in Canada. CSI laboratory studies work for only 2 to 3 cycles due to low incremental oil in subsequent cycles. However, in field pilots the CSI keeps operational after many years. This study intends to capture the full production mechanisms responsible of heavy oil production in CSI to better understand the phenomena in field applications.
A physical sandpack model was used to test the CSI response. The sandpack was saturated with live heavy oil of 7900 mPa.s viscosity at 24 ° C, and primary production was run. Five CSI tests were then conducted to simulate the performance under the gravity effects. The experiments were conducted in a horizontal and vertical mode injection respectively at high and low-pressure depletion rates using 70 mol % CH4 and 30 mol % C3H8 solvent mixture. The sandpack was Computed Tomography (CT) scanned after every cycle to provide information about the gas and oil saturations evolution.
When CSI was run on the horizontal core, the incremental oil recovery was negligible for both slow and fast drawdown rates. When the sandpack was vertically flipped and rapidly produced, the three CSI cycles exhibited higher recover, and similar incremental recovery per cycle. This result indicated that even at high drawdown pressures, gravity segregation can effectively maximize the cross-flow mixing between solvent and heavy oil to penetrate the un-swept areas.
The results of this study demonstrate the importance of gravity drainage in the CSI process, and the relative significance of gravity forces on successful oil recovery rates. The results of this study illustrate the limitations of previous horizontal laboratory tests and show an improved test configuration for modeling and prediction of the improved response observed in CSI pilots.
Permeability is a very critical tight reservoir parameter to characterize the process of oil/gas storage and production. In particular, distinct anisotropy of the shale reservoir, demands a practical method to measure permeabilities in multiple directions using the same core.
In this work, a systematic and practical pressure-pulse decay (PPD) technique is given to determine ultralow permeabilities of shale reservoir core in a cell with finite volume. The test gas can be non-adsorption gas such as helium or adsorption gas such as methane.
As described herein, given appropriate assumptions, the mathematical models based on the corresponding designed experiments (non-adsorption gas or adsorption gas) are formulated, and the exact solutions for the corresponding mathematical models are proposed using Laplace transform. Approximation techniques are further given to analyze experimental data to obtain radial and axial permeabilities. It is found that there are distinct anisotropy of shale reservoir and the permeability may be smaller when adsorption gas is used instead of non-adsorption gas.
Compared with traditional two-chamber PPD techniques, its advantages mainly lie in three points: only the pressure in one chamber is measured, which can lead to fewer pressure transducers and easier experimental operation. Meanwhile, the center of shale core needs not be drilled when the radial permeability is measured. What's more, the whole measurement is based on the same core and more information of the core can be obtained. However, it should also be noted that there is about 1 MPa difference of effective stress between our axial experiments and radial experiments. The effect of this difference on permeability is typically less than 5%, so the modified PPD can detect anisotropy efficiently.
Cai, Mingyu (China University of Petroleum) | Su, Yuliang (China University of Petroleum) | Sun, Zhixue (China University of Petroleum) | Li, Lei (China University of Petroleum) | Yuan, Bin (University of Calgary)
The uncertainties of fluvial reservoir geologic model are notably high due to complicated geological conditions and unknown strong heterogeneity. However, previous uncertainty analysis approaches mainly focus on qualitative evaluation. In this work, we proposed a novel workflow to quantify and optimize the geologic model uncertainties using the virtual outcrops.
First, the 3D geologic model is built by the virtual outcrops and geology database is established by the fine description of modern sedimentations, geologic outcrops and dense spacing areas. Next, geologic modeling algorithm is optimally selected based on the complexities of target reservoirs, computational speed and the shape of sand bodies. In this work, three indicators are proposed to evaluate the accuracy of geologic models, including matching coefficient of digital grey images to virtual outcrops, consistency of braided stream facies morphology and connectivity of inter-well effective sand bodies.
For the braided channel in Sulige field examples, the width of channel belt is 1500~3500m and the average sand thickness is 5m. For channel bar, the width is 350~650m, the length is 800~1500m and the thickness is 3~6m. The virtual outcrops help determine the vertical sequence and planar characteristics of sedimentary facies and sand bodies. The comparisons between established model and virtual outcrops indicate that the accuracy of geologic models increases as the denseness of hard data becomes smaller and the optimal well spacing and row spacing match up with the sand body size and average well spacing of studied area. The evaluation system proposed in this work demonstrates the degree of geologic reproduction, reasonability and partial uncertainty of the models to the real reservoir.
The value of this work is to provide a novel practical approach to optimize and quantify the uncertainties of geologic model. Furthermore, the established workflow can further be applied to identify the most significant controlling factor to determine geologic modeling in unconventional reservoirs.