Currently many lean gas EOR pilot projects are implemented in Eagle Ford shale. The major component of lean gas is methane. From the field feedback, there is always large discrepancy between production forecast (or reservoir simulation) and the field results. The natural fracture system is complex and the communication between natural fracture, matrix and hydraulic fractures is even more complicated. Comparing connecting natural fracture between wells with short and low fracture conductivity, the well interference and the resulted optimal well spacing significantly change. In this study, according to field feedback, some connecting natural fractures with high fracture conductivity are mapped between wells to better represent the field geology and production status.
A composition reservoir simulation model is built for Eagle Ford shale. Typical production curve of Eagle Ford shale is matched for the first three years of primary production, lean gas Huff and Puff (HNP) process is simulated for the next three years for the parent wells and child wells. As the main composition of lean gas is methane, different methane adsorption effects are quantified between wells to investigate its influence on production. For lean gas Huff and Puff process, normally the Minimum Miscibility Pressure (MMP) is above 4000 psi. During lean gas cycling process, methane is adsorbed and desorbed, and the effective methane amount used to enhance miscibility between gas and oil phases is reduced, thus the reservoir pressure is not elevated to as high as no gas adsorption case. The methane adsorption effect significantly affects the oil and gas production. Relative permeability hysteresis and capillary pressure hysteresis (gas trapping effect) are the first time systematically studied to quantify the gas EOR performance in pad level production of unconventional reservoirs. Considering gas trapping effects, the cumulative gas injection amount and production amount is much better matched to the field pilot results. The oil incremental benefit of gas Huff and puff process considering gas trapping effect is quantified.
To our best knowledge, this is the first time that both methane adsorption and gas trapping effects are studied for pad level Huff and Puff process with the realistic connecting natural fractures between wells. Better matching of the production data with pilot results confirms the successful application of these two mechanisms. Considering the realistic complex natural fracture effects also greatly contributes to the correct production forecast and efficient design of gas EOR project for unconventional reservoirs such as Eagle Ford shale and other major basins.
Tight oil production has increased dramatically and contributed to 61% of total US oil production in 2018. However, recovery factors for primary depletion with multistage fractured wells are low, typically less than 10%. Gas huff-n-puff emerges as a promising technique to push the recovery factor beyond 10% in tight oil reservoirs, based on laboratory studies, simulation and field pilot tests. A CO2 huff-n-puff pilot was implemented in the Midland Basin, and data collected demonstrated significant incremental oil recovery, but with higher than expected water-cut rise.
To understand the excessive water production, a compositional model was built. Eight pseudo-components were used to match the PVT lab results of a typical oil sample in the Wolfcamp shale. A lab scale model was established in our simulator to match the results of gas huff-n-puff experiments in cores, where key parameters were identified and tuned. A half-stage model consisting of five fractures was built, where stress-dependent permeability was represented by compaction tables. Then a sensitivity analysis was conducted to understand the roles of different mechanisms behind the abnormal high water-cut phenomenon on this scale. Our simulation results have shown that initial water saturation, IFT-dependent relative permeability, reactivation of water-bearing layers, and re-opening of unpropped hydraulic fractures may all affect water-cut after gas injection. Among them, re-opening of unpropped hydraulic fractures was the most critical one.
Data from a pilot test imply substantial water production after gas injection, which may impede oil production, but the underlying mechanisms are poorly understood. A numerical model is developed to study possible mechanisms for high water-cut pilot results. This study also intends to quantify the impact of high water cut on cyclic gas injection.
This paper presents a simple yet rigorous model and provides a methodology to analyze production data from wells exhibiting three-phase flow during the boundary-dominated flow regime. Our model is particularly applicable to analyze production data from volatile oil reservoirs, and should replace the less accurate single-phase models commonly used. The methodology will be useful in rate transient analysis and production forecasting for horizontal wells with multiple fractures in shales. Our analytical model for efficiently handling multi-phase flow is an adaptation of existing single-phase models. We introduce new three-phase parameters, notably fluids properties. We also define three-phase material balance pseudotime and three-phase pseudopressure to linearize governing flow equations. This linearization makes our model applicable to wells with variable rates and flowing pressures. We optimized the saturation-pressure path and further suggested an appropriate method to calculate three-phase pseudopressures. We validated the solutions through comparisons with compositional simulation using commercial software; the excellent agreement demonstrated the accuracy and utility of the analytical solution. We concluded that, during the boundary-dominated flow regime, the saturation-pressure relation given by steady-state path and tank-type model for volatile oil reservoirs leads to satisfactory results. We also confirmed that our definitions of three-phase fluid properties are well suited for ultra-low permeability volatile oil reservoirs. The computation time of our model is greatly reduced compared to a numerical approach, and thus the methodology should be attractive to the industry. Our model is efficient and practical to be applied for production data analysis in ultra-low permeability volatile reservoirs with non-negligible water production during the boundary-dominated flow regime. This study extends existing analytical model methodology for volatile oil reservoirs and is relatively easy for reservoir engineers to understand.
Well diagnostics in deep, offshore GoM are vital in order to interpret any issues related to productivity losses. This is especially important since any intervention in such wells is very costly. Multiphase flow is amongst leading causes of well productivity loss. This paper presents an integrated workflow that provides a solution to the challenge of quantifying multiphase PTA results in single and multiple commingled production cases. The workflow is used to monitor the performance of several wells over an extended period in a deep-water offshore reservoir under water/aquifer drive. It builds on a succession of PTA tests starting from single phase flow until water breakthrough and beyond. The results of historical PTA provided meaningful insights that were used as basis for actions that led to well and reservoir performance optimization.
Two-phase oil/water relative permeability measurements were conducted at ambient and high temperatures in two different rock-fluid systems; one using a clean Poly-Alpha-Olefin (PAO) oil and the other with Athabasca bitumen. The tests were performed in a clean sand-pack with the confining pressure of 800 psi, using deionized water as the aqueous phase. Both the JBN method and the history match approach were utilized to obtain the relative permeability from the results of isothermal oil displacement tests. The contact angle and IFT measurements were carried out to assess any possible wettability alteration and change in fluid/fluid interaction at higher temperatures.
Results, Observations, Conclusions: The results of the clean system using the viscous PAO oil confirmed that the two-phase oil/water relative permeability in this ultra-clean system is practically insensitive to the temperature. The slight variation in oil endpoint relative permeability, especially at ambient condition, was attributed to variations in the packing of sand. It was found that the history matching derived two-phase relative permeability from the highest temperature test provides reasonably good history matches of the other displacements that were conducted at lower temperatures. In addition, it is shown that the JBN approach based relative permeability curves show larger variations, primarily due to insufficient volume of water injection at lower temperatures, which makes the practical residual oil saturation much higher than the true residual. In contrast with the ultra-clean system, the results obtained with bitumen showed much larger variations in relative permeability with temperature.
Most of the reported studies involving history matching approach treat the low-temperature measurements as the base case and show that changes in relative permeability are needed to history-match the tests at higher temperatures. We have shown that the displacement done at the highest temperature provides a more reliable estimate of the relative permeability and, in some cases, this relative permeability can successfully history match tests done at lower temperatures. In view of the impracticality of injecting sufficient water to reach close to real residual oil saturation at low temperatures, it would be better to obtain relative permeability data at high temperatures for characterizing the two-phase flow behavior of viscous oil systems.
Rate-transient analyses (RTA) is a useful reservoir/hydraulic fracture characterization method that can be applied to multi-fractured horizontal wells (MFHWs) producing from low permeability (tight) and shale reservoirs. In this paper, a recently-developed three-phase RTA technique is applied to the analysis of production data from a MFHW completed in a low-permeability volatile oil reservoir in the Western Canadian Sedimentary Basin.
This new RTA technique is used to analyze the transient linear flow regime for wells operated under constant flowing bottomhole pressure conditions. With the new method, the slope of the square-root-of-time plot applied to any of the producing phases can be used to directly calculate the linear flow parameter,
The subject well, a MFHW completed in 15 stages, produces oil, water and gas at a nearly constant (measured downhole) flowing bottomhole pressure. This well is completed in a low-permeability, near-critical volatile oil system. For this field case, application of the new RTA method leads to an estimate of
The new three-phase RTA technique developed herein is a simple-yet-rigorous and accurate alternative to numerical model history-matching for estimating
Initial rate and decline are the two main parameters defining the economics of unconventional shale oil development. To improve economics, companies drill longer horizontal wells with more than twenty equidistant stages, different completion strategies and various additives such as surfactants and nano surfactants. This procedure evolves to factory mode in which tasks are optimized in timing and performance without attention to the matrix aspects of improving the recovery. Here, we report the design of a mutual solvent injection pilot in the Vaca Muerta unconventional reservoir during the completion of four unconventional shale oil wells. Reducing
Vaca Muerta has been long regarded as a water wet shale because of the limited water backflow post-fracking job. Alternating water injection was implementing assuming that the well productivity is driven by spontaneous imbibition, but this strategy has been unsuccessful as capillary pressure hysteresis drives this mechanism. We started studying Vaca Muerta from the rock microstructure using energy-dispersive spectrometry and focused gallium Ion Beam ablation FIB SEM images. The microstructure varied widely from millimeters in the same plug which could be expected because in shale rocks millimeters represent more years of deposition than in a conventional reservoir. We identified intercalations of massive water wet zones and strongly oil wet zones in the Vaca Muerta kitchen zone. The oil wet intercalations have high porosity and adsorption isotherm indicating 100 to 1000 times more permeability than the water wet zone. The water wet intercalations are highly saturated with water, and on the contrary, the oil wet intercalations are highly saturated with oil. The pilot designed consisted of four wells in which we will test different injection concentrations but keeping the total mass constant. In this manner, we will estimate the volume contacted by the solvent.
The laboratory protocol indicates a large percentage of macro and meso-pores. We implemented the dimethyl-ether injection which changes the interfacial tension, viscosity and wettability and we obtained the modified relative permeabilities which were the injection of dimethyl ether at 30% concentration along with the hydraulic fracture stimulation stages doubled the initial oil production rate.
The pilot consisted of five wells in which we will test different injection concentrations but keeping the total mass constant. In this manner, using the numerical simulation, we will estimate the volume contacted by the solvent.
Intercalations of high porosity high permeabilities zones in which the injection of a mutual solvent that reduces viscosity and could change wettability in oil wet/water-wet Vaca Muerta improving matrix connectivity.
Zhao, Bochao (Shell International Exploration and Production) | Ratnakar, Ram (Shell International Exploration and Production) | Dindoruk, Birol (Shell International Exploration and Production) | Mohanty, Kishore (The University of Texas at Austin)
Accurate estimation of relative permeability is vital for decision making in upstream applications from project appraisal to field development and evaluation of various field development options. As relative permeability is a function of both rock and fluid properties, it is harder to generalize it over a wide combination of rocks and fluids. In addition to this complexity, it is hard to gather coherent sets of data to develop a correlation covering the domain of interest for most projects. As a result, fast and reliable relative permeability prediction method is missing in literature. In this study, we identify Euler number (
In order to achieve our objective, first, we developed a machine learning model based on random forest algorithm (
The investigation based on machine learning of pore network simulation results in combination with the available data suggests that phase saturation and Euler numbers are the two dominant parameters affecting the relative permeability. In particular, it shows that Variation in relative permeability with different rock-fluid parameters (that along with intial fluid distribution can cause the variation in Euler number) is significant even when saturation is fixed. In other words, the relative permeability is multivalued function of saturation, as hysteresis models also indicate. This suggests neither of saturation or Euler number alone is sufficient for relative permeability prediction. At a fixed saturation (zero-dimensional volumetric abundance) and Euler number coordinates, the relative permeability is very consistent and vary insignificantly across different cases, suggesting thesetwo parameters as first-order predictors. Euler number characterizes the fluid connectivity/distribution, while saturation represents the net volumetric fluid quantity. We believe that Euler number has been the missing first-order predictor in traditional saturation-based predictive relative permeability models. Most importantly, we identify and present the quantitative relationship between relative permeability and Euler characteristic, and present a reliable correlation to determine the relative permeability based on Euler number and saturation.
Variation in relative permeability with different rock-fluid parameters (that along with intial fluid distribution can cause the variation in Euler number) is significant even when saturation is fixed. In other words, the relative permeability is multivalued function of saturation, as hysteresis models also indicate. This suggests neither of saturation or Euler number alone is sufficient for relative permeability prediction.
At a fixed saturation (zero-dimensional volumetric abundance) and Euler number coordinates, the relative permeability is very consistent and vary insignificantly across different cases, suggesting thesetwo parameters as first-order predictors. Euler number characterizes the fluid connectivity/distribution, while saturation represents the net volumetric fluid quantity. We believe that Euler number has been the missing first-order predictor in traditional saturation-based predictive relative permeability models.
Most importantly, we identify and present the quantitative relationship between relative permeability and Euler characteristic, and present a reliable correlation to determine the relative permeability based on Euler number and saturation.
To the best of our knowledge, this is the first successful attempt at directly investigating the quantitative relationship between Euler number and relative permeability based on machine learning of experimental SCAL data in combination with pore network simulation results. This work provides the necessary framework and lends itself for further research and development using additional data as time goes on along with more advanced numerical simulation and data analysis models.
After nearly thirty years of research and development, it is now commonly agreed that Low Salinity Waterflood (LSW) is an attractive enhanced oil recovery (EOR) method because of its incremental oil recovery performance, reasonable operating cost and low environmental impact compared to conventional waterflood and other EOR processes. From the past studies, LSW is known as a process that comprises many mechanisms, i.e. multiple ion exchanges, wettability alteration, complex geochemical reactions, and fines migration and deposition. However, most studies in the literature have only focused on a single recovery mechanism, with varying, sometimes contradictory conclusions. This paper presents: (1) a comprehensive model that takes into account all the different important physics in LSW, i.e. fines transport, geochemistry and wettability alteration; (2) validation with a core-flood experiment; and (3) field-scale optimization of LSW.
A model for fines transport has been developed and incorporated in an Equation-of-State compositional reservoir simulator with geochemistry and wettability alteration modeling. The proposed model is capable of accounting for complex transport phenomena of fines (clay) particles in porous media including fines deposition, entrainment, and plugging. The simulator also considers physical phenomena in the oil/rock/brine system such as aqueous chemical equilibrium, rate dependent mineral reactions, multiple ion exchanges, and relative permeability alteration due to wettability changes. Validations with a LSW core-flood experiment were carried out, which provide insights into the important mechanisms for the incremental oil recovery by LSW.
The proposed model shows good agreement in terms of oil recovery and pressure drop with a benchmark LSW core-flood experiment which was conducted with a non-polar oil and in which migration of clay particles and their plugging of pores were considered as the main recovery mechanism. It is shown that the proposed model can efficiently capture the important physics in LSW processes related to fines transport. The impact of formation damage during LSW can be efficiently evaluated using this model. Finally, an optimization workflow helps maximize the recovery factor of the LSW process.
To our knowledge, this paper describes one of the first LSW mechanistic models to capture the three principal mechanisms of LSW, i.e. fines transport, geochemistry, and wettability alteration. Excellent match with laboratory experiments and field-scale optimization reinforce validity of the model. The proposed workflow can be extended to other recovery methods such as Low-Salinity Polymer or Low-Salinity Alkali-Surfactant-Polymer.
Surfactant-Assisted Spontaneous Imbibition (SASI) and gas injection have been proven to improve production from Unconventional Liquid Reservoirs (ULR). However, the novelty of the method has resulted in a few publications to date. This study utilizes numerical modeling to upscale laboratory data of SASI for completion purposes and gas injection plus SASI for EOR. Novel gas and aqueous-phase injection strategies following primary depletion are designed based on actual completion and production data. Multiple sequencing configurations for both surfactant and gas injection are tested to propose the best combined-EOR scheme for ULR.
Parameters related to the mechanism of SASI and gas injection are retrieved from CT-generated core-scale model of laboratory experiments. SASI and gas injection experimental results were upscaled to model production response of a hydraulically fractured well with realistic fracture geometry and conductivity. The core-scale model was created to determine the diffusion coefficient, relative permeability, and capillary pressure curves by history-matching the laboratory data. The field-scale model was developed with a dual-porosity compositional model to predict production enhancement for various combined-EOR schemes in ULR.
Wettability and IFT alteration are the two primary mechanisms for SASI in enhancing production. Experimental studies revealed that surfactant solution recovered up to 30% OOIP, whereas water alone only recovered approximately 10% OOIP. Capillary pressure and relative permeability constructed from scaling group analysis and core-scale numerical models showed that surfactant addition enhances the two curves. On the other hand, gas injection EOR was found to be driven by multi-contact miscibility and diffusion. Parameters related to both methods were applied to the field-scale model for multiple completion and EOR schemes. Results demonstrate that the combination of SASI and gas injection possesses significant potential in improving production rates and estimated ultimate recoveries (EUR) in ULR. Soak times, surfactant concentration, injection pressure, duration of the cycle, and cumulative gas injection control the level of enhancement. With a large number of control variables, specific customizations can be optimized to suit criteria of different field applications.