Hosseininoosheri, P. (The University of Texas at Austin) | Hosseini, S. A. (The University of Texas at Austin) | Nunez-Lopez, V. (The University of Texas at Austin) | Lake, L. W. (The University of Texas at Austin)
The relative partitioning of CO2 during and after CO2 injection in a CO2-EOR process is affected by several parameters. While many geological properties cannot be changed in a specific hydrocarbon (HC) reservoir, it could be shown that an intelligent selection of CO2 injection strategy improves both the incremental oil recovery and CO2 storage capacity and security. Therefore, we investigated and discussed the partitioning of CO2 among different phases (oil, gas, and brine) after two well-known CO2 inejction schemes using field-scale compositional reservoir flow modeling in the SACROC (Scurry Area Canyon Reef Operators Committee) unit, Permian Basin. First, we used a high-resolution geocellular model, which was constructed from wireline logs, seismic surveys, core data, and stratigraphic interpretation. As the initial distribution of fluids plays an important role in CO2 partitioning, a comprehensive pressure-production history matching of primary, secondary, and tertiary recovery was completed. The hysteresis model was used to calculate the amount of CO2 trapped as residual. CO2 solubility into brine was verified based on previous experiments. The model results showed a new understanding of relative CO2 partitioning in porous media after a CO2-EOR process. We compared the contribution of CO2 trapping mechanisms and the sweep efficiency of Walter-Alternating-Gas (WAG) and Continous-Gas-Injection (CGI). We found that WAG injection showed a significantly superior behaviour over CGI. WAG not only decreased the amount of mobile CO2 (structural trapping), but also resulted in a competitive incremental oil recovery in comparison with CGI. Thus, clearly WAG injection ispreferred as it strongly enhances CO2 storage efficiency and containment security. The present work provides valuable insights for optimizing oil production and CO2 storage in carbonate reservoirs like SACROC unit. In other words, this work helps decision makers to set storage goals based on optimized project risks.
Aqueous foam has been demonstrated through laboratory and field experiments to be a promising conformance control technique. This study explores the foaming behavior of a CO2-soluble, cationic, amine-based surfactant. A distinguishing feature of this surfactant is its ability to dissolve in supercritical CO2 and to form Wormlike Micelles (WLM) at elevated salinity. Presence of WLM led to an increase in viscosity of the aqueous surfactant solution. Our study investigates how the presence of WLM structures affect transient foam behavior in a homogenous porous media (sand pack).
Sand pack foam flooding experiments were performed with two aqueous phase salinities: low salinity (15 wt. % NaCl) associated with spherical-shaped micelle and high salinity (20 wt. % NaCl) associated with WLM. We compared the onset of strong foam propagation and foam apparent viscosity buildup rate between the two salinity cases. The effect of WLM presence in transient foam behavior was investigated for co-injection and water-alternating-gas (WAG) injection strategies. In all foam flooding experiments, the surfactant was delivered in the CO2 phase.
Strong foam was generated in all foam flooding experiments, with an apparent foam viscosity of at least 600 cp for co-injection and 200 cp for WAG floods after five total injected pore volumes. The observed strong foam indicated that the delivery of surfactant in the CO2 phase was successful and that the surfactant molecules partition to the water phase in the sand pack. In comparison to the low salinity cases, the high salinity foam floods associated with the presence of WLM led to better foam performance. We observed an earlier onset of strong foam propagation as well as a higher apparent viscosity buildup rate. Better foam performance at higher salinity may be attributed in large part to the presence of WLM structures in the foam liquid phase. Entanglement of these WLM structures may have led to in-situ viscosification of the foam liquid phase and an increase in disjoining pressure between foam films. Both phenomena may have reduced the rate of foam film coalescence.
WLM structures behave similarly to polymer molecules. Our study may offer evidence that WLM is a valid alternative to polymer as an additive to enhance foam conformance control performance. Some potential advantages of WLM over polymer include: Delivery of surfactant in the gas phase (to alleviate the injectivity issue typically associated with high viscosity polymer-surfactant solution), resistance to extreme temperature and salinity, and reversible shear degradation.
Carbon dioxide (CO2) flooding is a mature technology in oil industry, which finds broad attention in oil production during tertiary oil recovery (EOR). After five decade’s developments, there are many successful reports for CO2 miscible flooding. However, operators recognized that achieving miscible phase is one of big challenge in fields with extremely high minimum miscible pressure (MMP) after considering the safety and economics. Compared with CO2 miscible flooding, immiscible CO2 flooding demonstrates the great potentials under varying reservoir/fluid conditions. A comprehensive and high-quality data set for CO2 immiscible flooding are built by collecting various data from books, DOE reports, AAPG database, oil and gas biennially EOR survey, field reports and SPE publications. Important reservoir/fluid information, operational parameters and project performance evaluations are included, which provides the basis for comprehensive data analysis. Combination plot of boxplot and histogram are generated, where boxplots are used to detect the special cases and to summarize the ranges of each parameter; histograms display the distribution of each parameter and to identify the best suitable ranges for propose guidelines.
Results show that CO2 immiscible flooding could recover additional 4.7 to 12.5% of oil with average injection efficiency of 10.07 Mscf/stb; CO2 immiscible technique can be implemented in light/medium/heavy oil reservoirs with a wide range of net thickness (5.2 - 300 ft); yet in heavy oil specifically reservoir (oil gravity <25 °API) with thin layer (net thickness< 50 ft) is better.
Pilot testing results and economics from a novel electrochemical desalination technology for enhanced oil recovery (EOR) produced water are presented. The pilot objectives were: (1) economically desalt produced water to improve hydrocarbon recovery and lower polymer consumption costs for chemical flood EOR; (2) inform full scale plant development with a field pilot; and (3) optimize pre-filtration, chemical consumption, and energy use to realize a greater than 20% return on investment through reduced polymer consumption.
The paper will present EOR operators with a novel option to reuse produced water as low salinity injection water and recycle polymer to reduce chemical EOR flood operating costs.
Alkaline-surfactant-polymer (ASP) flooding is an effective technique to improve oil recovery. It has been applied typically after a water flood. Recently, there has been a successful field test where an ASP flood was conducted after a polymer flood. Is the ASP flood after a polymer flood more effective than an ASP flood after a water flood? It is difficult to conduct this experiment in exactly the same location in a field. The goal of this study is to answer this question in a laboratory heterogeneous quarter 5-spot model. A heterogeneous quarter 5-spot sand pack of size 10″ × 10″ × 1″ was constructed. Two sands with a permeability contrast of 10:1 were packed into a 2D square steel cell. An alkali-surfactant formulation was identified that produced ultra-low interfacial tension with the reservoir oil (27 cp). In one experiment (WF-ASP), waterflood was conducted first followed by the ASP flood. In a second experiment (PF-ASP), polymer flood was conducted first followed by the ASP flood. The ASP formulation and slug size were kept the same. Secondary water flood of the heterogeneous quarter 5-spot recovered 22% OOIP. Post-waterflood ASP flood recovered 32% OOIP additional oil with a cumulative (WF-ASP) oil recovery of 54%. Secondary polymer flood of the same heterogeneous quarter 5-spot yielded 50% OOIP. Post-polymerflood ASP flood recovered 32% OOIP additional oil with a cumulative (PF-ASP) oil recovery of 82% OOIP. The water flood and the subsequent ASP flood swept a large part of the high permeability region and a small part of the low permeability region. The polymer flood swept all of the high permeability region and most of the low permeability region. The subsequent ASP flood swept the polymer-swept regions. These experiments demonstrate that the polymer flood - ASP flood combination is more effective than the water flood - ASP flood combination.
Spontaneous and forced imbibition are recognized as important recovery mechanisms in naturally fractured reservoirs as the capillary force controls the movement of the fluid between the matrix and the fracture. For unconventional reservoirs, imbibition is also important as the capillary pressure is more dominant in these tighter formations, and the theoretical understanding of the flow mechanism for the imbibition process will benefit the understanding of important multiphase flow phenomenons like water blocking. In this paper, a new semi-analytic method is presented to examine the interaction between spontaneous and forced imbibition and to quantitatively represent the transient imbibition process. The methodology solves the partial differential equation of unsteady state immiscible, incompressible flow with arbitrary saturation-dependent functions using the normalized water flux concept, which is very identical to the fractional flow terminology used in traditional Buckley-Leverett analysis. The result gives a universal inherent relationship between time, normalized water flux, saturation profile and the ratio between co-current and total flux. The current analysis also develops a novel stability envelope outside of which the flow becomes unstable due to strong capillary forces, and the characteristic dimensionless parameter shown in the envelope is derived from the intrinsic properties of the rock and fluid system and can describe the relative magnitude of capillary and viscous forces at the continuum scale. This dimensionless parameter is consistently applicable in both capillary dominated and viscous dominated flow conditions.
Ross, T. S. (New Mexico Institute of Mining & Technology) | Rahnema, H. (New Mexico Institute of Mining & Technology) | Nwachukwu, C. (New Mexico Institute of Mining & Technology) | Alebiosu, O. (ConocoPhillips Co) | Shabani, B. (Oklahoma State University)
Steam injection—a thermal-based enhanced oil recovery (EOR) process—is used to improve fluid mobility within a reservoir, and it is well known that it yields positive results in heavy-oil reservoirs. In theory, steam injection has the potential of being applied in light-oil reservoirs to enable vaporization of in-situ reservoir fluids, but field developments and scientific studies of this application are sparse. Conventional displacement methods like water-flooding and gas-flooding have been applied to some extent, however, oil extraction in such reservoirs relies on recovery mechanisms like capillary imbibition or gravity drainage to recover oil from the reservoir matrix. Furthermore, low-permeability reservoir rocks are associated with low gravity drainage and high residual oil saturation.
The objective of this study is to evaluate the potential of steam injection for light (47°API) oil extraction in naturally-fractured reservoirs. It is theorized that this method will serve as an effective tool for recovery of light hydrocarbons through naturally-fractured networks with the benefit of heat conduction through the rock matrix. This research investigates the application of light-oil steamflood (LOSF) in naturally- fractured reservoirs (NFR).
A simulation model comprised of a matrix block surrounded by fracture network was used to study oil recovery potential under steam injection. To simulate gravity drainage, steam was injected through a horizontal well completed in the upper section of the fracture network, while the production well was completed at the bottom of the fracture network. The simulation included two different porous media: (1) natural fractures and (2) matrix blocks. Each of these porous media was assumed to be homogeneous and characterized based on typical reservoir properties for carbonate formations. This study also analyzed the impact of different recovery mechanisms during steam injection for a light-oil sample in NFR, with reservoir sensitivity examined, based on varying amounts of vaporization, injection rate, permeability, matrix height and capillary pressure. Of these, vaporization was found to be the dominant factor in the application of LOSF in NFR, as described in detail within the results.
This paper presents modeling CO2 enhanced oil recovery (EOR) flood performance through the application of dimensionless scaling for both forecasting and surveillance purposes. While the methodology has been used successfully for West Texas CO2 floods for more than two decades, a recent modification in the process enhances the certainty of forecasted tertiary response based on simulation and analog results. The primary focus of this paper is on how this new approach improves the use of analog or observed production history to develop more reliable forecasts for EOR processes. Business units favor analog methods since they are fast, adaptable and explicit.
Analog tertiary production response is the incremental oil production over an estimated base waterflood oil recovery. The original formulation, published in a different paper (
This paper summarizes BP's Alaskan viscous oil resource appraisal strategy to de-risk viscous oil resource progression with a goal to improve recovery factor by 10%. A key to recovery improvement is application of improved oil recovery/enhanced oil recovery (IOR/EOR) methods. However, even after detailed studies, moving to the next stage including field pilots is not always easy in the mature and remote Alaskan North Slope.
The paper also covers BP's Alaskan viscous oil technology strategy, extraction technologies selection, simulation and analytical studies, laboratory studies, and field trials for various shortlisted methods. A comprehensive study strategy conducted for progressing chemical EOR processes is discussed. The paper also addresses the challenges of obtaining new core and fluid samples for laboratory studies and logistical and economic considerations for field trials due to location and weather conditions in this part of the world.
In-situ upgrading (IU) is a promising method of improved viscous and heavy oil recovery. The IU process implies a reservoir heating up and exposition to temperature higher than 300°C for long enough time to promote a series of chemical reactions. The pyrolysis reactions produce lighter oleic and gaseous components while a solid residue remains underground. In this work, we developed a numerical model of IU based on lab experiences (kinetics measurements and core experiments) and validated results applying our model to an IU test published it the literature. Finally, we studied different operational conditions searching for energy-efficient configurations.
In this work, two types of IU experimental data are used from two vertical-tube experiments with Canadian bitumen cores (0.15 m and 0.69 m). A general IU numerical model for the different experimental setups has been developed and compared to experimental data, using a commercial reservoir simulator framework. This model is capable to represent the phase distribution of pseudo-components, the thermal decomposition reactions of bitumen fractions and the generation of gases and residue (solid) under the cracking conditions.
Simulation results for the cores submitted to 370°C and production pressure of 15 bar, have shown that oil production (per pseudo-component) and oil sample quality were well-predicted by the model. Some differences in gas production and total solid residue were observed with respect to laboratory measurements. Computer-assisted history matching was performed using an uncertainty analysis tool on the base of the most important model parameters. In order to better understand IU field-scale test results, the Shell’s Viking pilot (Peace River) was modeled and analyzed with proposed IU model. The appropriated grid-block size was determined and calculation time was reduced using the adaptive mesh refinement technique. The quality of products, the recovery efficiency and the energy expenses obtained with our model were in good agreement with the field test results. Also the conversion results (upgraded oil, gas and solid residue) from the experiments were compared to those obtained in the field test. Additional analysis was performed to identify energy efficient configurations and to understand the role of some key variables, e.g. heating period and rate, the production pressure, in the global IU upgrading performance. We discuss these results which illustrate and quantify the interplay between energy efficiency and productivity indicators.