Luo, Haishan (The University of Texas at Austin) | Li, Zhitao (Ultimate EOR Services LLC) | Tagavifar, Mohsen (The University of Texas at Austin) | Lashgari, HamidReza (The University of Texas at Austin) | Zhao, Bochao (The University of Texas at Austin) | Delshad, Mojdeh (The University of Texas at Austin) | Pope, Gary A. (The University of Texas at Austin) | Mohanty, Kishore K. (The University of Texas at Austin)
Polymer flooding has been commercially applied to a number of viscous oil fields in the past decade and gradually gained more popularity. Due to limited injectivity in viscous-oil reservoirs, a relatively low polymer viscosity is usually used to avoid excessive injection pressure. In such a case, mobility ratio of polymer solution to oil is much greater than one, which implies unstable flow and strong viscous fingering. Existing reservoir simulators lack the capability of modeling such a physical phenomenon. Since many viscous-oil reservoirs have high permeability contrast between layers, we are motivated to study, for the first time, the impact of crossflow between different layers considering the presence of viscous fingering.
Numerical modeling polymer floods with crossflow in a layered viscous-oil reservoir is difficult due to two major challenges: first is how to correctly allocate flow rates from the wellbore to multiple layers; and second is how to capture the viscous fingering effect without using excessively fine grids. To address the first issue, we developed an implicit well-rate-allocation model based on the potential method, which fully couples all the wellbore segments of each well with reservoir gridblocks to ensure a physical wellbore pressure. To deal with the second challenge, we implemented the effective fingering model, which is an upscaling model that lumps all the viscous fingers in a coarse grid block into one fictitious finger to allow for accurate estimation of fingering strength and growth during unstable flows. Both models were validated individually against the analytical solution or experimental data.
The integrative module including the two new capabilities was used to simulate a polymer flood following a waterflood in a layer-cake reservoir in North America with moderate oil viscosity. We observed the fast propagation of water fronts and small fingering fraction in high permeability layers during the waterflooding phase, indicating active channeling and viscous fingering. The subsequent polymer flooding minimized both factors of oil bypassing and led to stable flow and high sweep efficiency. Without the implicit well-rate-allocation model, crossflow was overestimated and wellbore pressures of different well blocks were not consistent. Without the effective-fingering model, oil recovery was overestimated due to the lack of accounting for viscous fingering. The simulation results indicated that polymer flooding improved both displacement and sweep efficiencies.
The model has shown comprehensive capabilities in reservoir simulations of polymer floods including unstable floods and crossflows between layers. This is a major significance to optimization of non-thermal viscous-oil EOR projects and also making more informed operational decisions for field developments.
This paper presents the results of an experimental investigation to determine the mechanisms of pore plugging and permeability reduction near SAGD screen liners. The aim is to arrive at a liner design that maximizes wellbore productivity without compromising the sand control function of the liner.
We set up a large-scale Sand Retention Testing (SRT) facility that accommodates a multi-slot liner coupon at the base of a sand-pack with representative grain shape and particle size distribution (PSD) of typical oil sands. Brine is injected at different flow rates and pressure differences across the coupon and the sand-pack as well as the mass and PSD of the produced sand and fines are measured during the test. Further, the PSD and concentration of migrated fines (<44 microns) along the sand-pack are determined in a post-mortem analysis. The testing results are used to assess the effect of slot size and slot density on the sand control performance as well as pore-plugging and permeability alterations near the sand-control liner.
We observed that the slot size, slot density and flow rate highly affect the concentration and PSD of produced fines as well as accumulated fines (pore clogging) above the screen. For the same flow rates and total injected pore volume, wider screen aperture and higher slot density result in lower fines accumulation above the screen but more sanding. Further, the variation of slot density alters the flow convergence behind the slots, hence, the size and concentration of mobilized fines. Results indicate that higher fines concentration near the screen reduces the retained permeability, hence, lowers the wellbore productivity.
This paper provides a new insight into pore plugging and fines migration adjacent the sand control liner. It also introduces a new testing method to optimize the design of sand control liners for minimum productivity impairment in SAGD projects.
The steam-assisted gravity drainage (SAGD) method is an efficient way of producing oil from many of Canada's Oil Sands reservoirs. Predicting oil production and steam injection rates is required for planning and managing a SAGD operation. While this can be done by simulating the fluid flow using commercially available thermal simulators, drainage area simulations can take days to run. This also involves significant expense for a business in the form of simulator license fees. For this reason, a proxy that reasonably predicts oil production and steam injection rates with low computational effort would be valuable.
In this paper, a reliable proxy for predicting SAGD performance is developed. This model can handle different operating pressure strategies and uses a distinctive approach to capturing the impact of reservoir heterogeneity. The approach is an approximate solution using a semi analytical model based on relevant theories including Butler's SAGD theory. The model is orders of magnitude faster than full simulation and provides performance forecasts which have a level of accuracy suitable for many practical applications within an operating oil sands business.
To capture the impact of near wellbore heterogeneity a novel parameter which accounts for the degree of near-well reservoir connectivity was developed. This parameter is calculated based on properties such as permeability, porosity and oil saturation inside an assumed 90-degree steam chamber above the producer. This parameter can take into account the distance of shale barriers above the producer which can act as a baffle/barrier for steam chamber development.
First, this paper outlines the core theory underlying the model and then, by showing different examples will demonstrate its accuracy and applicability within an operating SAGD business. Results show strong correlation between simulated key production parameters such as peak oil rate and the parameter developed to account for near wellbore heterogeneity. By modifying the proxy to consider this parameter, the authors demonstrate a strong correlation between complex 3D thermal simulator results and this model in terms of oil production, cumulative steam oil ratio (cSOR) and instantaneous steam oil ratio (iSOR) predictions.
A solvent enhanced steam drive pilot in the Peace River area in Canada was executed over a period of two years on an inverted 5-spot pattern to evaluate bitumen uplift and solvent recovery. Data quality and uncertainty management were used to assure conclusive results for the pilot; in particular, this paper focuses on how sampling played a key role in providing conclusive results. Especial focus is provided to the design, performance, execution, and learnings from the use of the automatic proportional samplers which was particularly challenging, considering their novel use on heavy oil production containing abrasive material such as sand and H2S. Moreover, to determine solvent production, several newly developed algorithms were tested to split the solvent and bitumen compositions, since they overlap over a wide range of components. Results from the pilot show that significant errors and misinterpretations can occur while evaluating solvent recovery whenever the assumptions under the solvent-bitumen split algorithms are not checked against frequent sampling data. The pilot also provided best practices for the utilization of proportional auto samplers in heavy oil production in the presence of abrasive material inherent to in-situ production, and the sampling of gas streams with heavy condensate for the accounting of solvent production through casing vent gas.
Throughout the past five decades, the heavy oil industry has developed various in-situ techniques for oil recovery from the vast global heavy oil reserves. The diversity of these techniques goes hand in hand with the diversity of the world reserves in terms of viscosity, burial depth, and reservoir complexity. Reservoirs exist, however, wherein the currently available commercial methods might not be technically and economically feasible. In particular, reservoir quality and caprock integrity can impose significant limitations on the feasibility of conventional methods, such as steam assisted gravity drainage (SAGD). This paper summarizes the results of a series of field trials in weakly cemented formations based on the creation of highly conductive multiazimuth vertical planes (MAVP) in soft formations. These planes are mechanically initiated and hydraulically propagated and have typical dimensions of 0.03×5×30 m and can be used in a new steam injection design. The potential application of this technique to enhanced oil recovery is investigated using a thermal reservoir simulator.
Reservoir simulations show promising results in terms of cumulative steam oil ratio (CSOR) and oil production rate. Stabilized production was observed immediately after the startup and CSOR dropped to under 3.0 m3/m3 in less than two years. The overall performance is nearly comparable to that of conventional SAGD, while it outperforms SAGD in certain conditions, including low vertical permeability and in the presence of low permeable shale streaks. Simulation results show that the performance of MAVP is nearly unimpaired when planes’ projection is discontinuous in either vertical or horizontal directions. The results also showed that the presence of a confined top water zone does not have a detrimental impact on the performance of MAVP; however, penetration into the top water zone must be avoided to achieve the best results in terms of CSOR. While surface mining and variations of SAGD are respectively used for very shallow and relatively deep reservoirs, the new methodology is applicable to reservoirs in the depth range of 70 to 600 m, where weak caprock integrity can impose a significant challenge. In addition, complex reservoir features, such as the presence of low permeable shale layers or low vertical permeability, have minimal effect on the performance of this technique.
Thermal well service conditions have presented a significant challenge to the sealability of casing connections. Over the years, industry has established various standards, protocols and guidelines for assessing the sealability performance of casing connections to be used in thermal well applications. The use of Finite Element Analysis (FEA) has been increasingly incorporated into the connection performance evaluation process. FEA evaluation requires the use of an appropriate criterion that relates the connection seepage rates to the applied internal pressure differential, contact stress profile on the radial seal surface, surface roughness, thread compounds and various other factors such as environmental impacts.
This paper presents experimental work that has been undertaken to investigate the metal-to-metal seal behavior in premium casing connections. The physical tests simulated a series of metal-to-metal seals under various levels of gas pressure and seal contact stress. The impacts of seal length, tubular diameter, surface roughness, thread compound and corrosive medium were investigated. The experimental results were used to validate the sealability criterion which is proposed for use in evaluating thermal well casing connections.
Brown, Joel (Saudi Arabia Chevron) | Lwin, Al (Saudi Arabia Chevron) | Barge, David (Saudi Arabia Chevron) | Al-Mutairi, Ghanim (Saudi Arabia Chevron) | Al-Gamdi, Saleh (Saudi Arabia Chevron) | Kumar, Raushan (Chevron Energy Technology Company) | Littlefield, Brian (Chevron Energy Technology Company)
A large-scale steamflood pilot test has been successfully completed in the 1st Eocene reservoir. The 1st Eocene is a multi-billion-barrel heavy oil carbonate reservoir in the Wafra field, located in the Partitioned Zone (PZ) between the Kingdom of Saudi Arabia and Kuwait. The pilot was the first multi-pattern steamflood in a carbonate reservoir in the Middle East.
The pilot consisted of sixteen 2.5-acre inverted 5-spot patterns with associated steamflood and production facilities. The primary objective of the pilot was to identify and mitigate technical and economic risks and uncertainties in carbonate steamflooding to assist in the broader Wafra Steamflood full-field development decisions. In the execution of the pilot, performance measures were developed to assess steamflood success in a carbonate reservoir. These success measures included key metrics that were prerequisites for the full field steamflood development of the field. In September 2013, the pilot reached a key milestone and success measure when steam zone development was assessed in the pilot area. Another key success measure was the successful validation of pilot results using thermal reservoir simulation.
The 1st Eocene reservoir in Wafra field, PZ is a challenging asset, with the potential for large reserve additions, in which steamflood technology and learnings from conventional steamflood fields are being leveraged. In this paper, we will share the steamflood results achieved in the pilot with focus on the accomplishment measures set for the project and the progress made in identifying and mitigating key uncertainties in carbonate steamflooding.
As steam-assisted gravity drainage (SAGD) producers continue to look for methods for enhancing oil recovery, understanding the dynamics at play in the evolution of the steam chambers becomes critical. Steam thief zones introduce operational risks affecting the economic recovery of the bitumen. Sensitive reservoirs need careful monitoring to avoid compromising cap rock integrity and to detect steam breakthrough.
A need exists for real-time, spatially sensitive temperature monitoring in production, injection, and observation wells. Although such monitoring has been used in production and injection wells for decades, operators of SAGD observation wells (with typical two to six per pad) mostly used either piezometers for single-point pressure and temperature measurements and/or multiple-point thermocouple bundles. Distributed temperature sensing (DTS) application in these remote environments has been limited by availability of infrastructure with temperature-controlled environment and power supply in close proximity to the wellhead, which most DTS interrogation equipment requires.
In this paper we introduce and demonstrate the installation of a new stand-alone, low-power DTS solution to address the specific needs of remote observation wells within a northern Alberta SAGD field. An acquisition system with extended working temperature range and small geometry form is installed within enclosures equipped with temperature-control devices and zonal certification. Downhole temperature data is transmitted continuously over a cellular network to a secure server with data-trending software for ease of viewing.
The system was installed in February 2015 and the downhole temperature data accessible through web browser download during the field trial period.
Solvent injection alone, or in combination with steam, is currently receiving considerable attention as an emerging in-situ oil sands technology in Alberta. The goal of solvent and steam assisted recovery processes is to reduce energy consumption and greenhouse gas emissions over the use of steam alone. Pilot studies in the field indicate a significant difference between reservoir simulation predictions, and field performance and previous studies have demonstrated that the assumption of instantaneous equilibrium is not valid for solvent-bitumen interactions and can introduce significant inaccuracies to the modelling results. In addition to assuming non-equilibrium, this study seeks to determine the mechanism of solvent dissolution in bitumen and the expected improvement in oil recovery, if any, when a solvent is injected with steam.
The unique aspect of this work is that instantaneous phase equilibrium is not assumed, as is typical of numerical simulations for solvent-steam applications. Partial equilibrium was not based on an empirical factor or concept. Rather, this study bases phase equilibrium on an analytical model of the dissolution and mobilization of a drop of bitumen inside a pore, by solvent and heat. The analytical solution indicates that the time required for a drop of bitumen to mobilize towards the production well is at least three times greater for solvent via diffusion and dispersion than by heat conduction. The analytical solution was developed for solvent injection, heat injection, and co-injection for several boundary conditions.
The single drop model is built into a new thermal compositional simulator developed for this study. Thermal solvent injection processes were investigated for non-equilibrium phase behaviour. The results were compared with the case of instantaneous equilibrium, showing the reason for the previous lack of accurate predictions for solvent injection in oil sands reservoirs.
The results and extensions of this work will be of interest in heavy oil production because they serve to explain the unexpected performance and frequent lack of success of these processes. This model is capable of precisely predicting solvent injection concentration, flow rate, and recovery at the field scale, making it possible to determine whether or not solvent injection is appropriate in any given situation.
Relative permeability plays a significant role in predicting oil rate and ultimate oil recovery factor. The literature reveals that same set of relative permeability is often used to predict the ES-SAGD performance regardless of not only the downhole operating temperature but also the injected solvent concentration. This can lead to significant errors when predicting the ES-SAGD performance and its economical feasibility. In paper SPE-180713-MS, SAGD relative permeability was presented as a function of temperature. In this paper, a series of realistic ES-SAGD relative permeability curves were developed based on experimental work combined with simulation studies.
A typical Athabasca oil and sand were used to obtain the experimental data and construct relative permeabilities using unsteady-state method. First residual oil saturations were determined in presence of hot water and steam flooding under SAGD condition at a given temperature. Following that, a typical n-alkane (n-heaxane) solvent was co-injected with steam at different concentrations varying from one to 25 weight percent of the injected steam while the operating temperature was kept constant. The produced oil and water volumes were collected and measured during the hot water, steam injection, and solvent co-injection experiments. The data were utilized to construct the relative permeability curves at a given operating temperature (200 °C) and various solvent concentrations. Finally, a series of reservoir simulations were performed to history match the lab experiments and examine the accuracy of inferred relative permeability curves.