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.
Andersen, Pål Østebø (Dept. of Energy Resources, University of Stavanger, The National IOR Centre of Norway, University of Stavanger) | Qiao, Yangyang (Dept. of Energy and Petroleum Technology, University of Stavanger) | Standnes, Dag Chun (Dept. of Energy Resources, University of Stavanger) | Evje, Steinar (The National IOR Centre of Norway, University of Stavanger, Dept. of Energy and Petroleum Technology, University of Stavanger)
This paper presents a numerical study of water displacing oil by combined co-current / counter-current spontaneous imbibition (SI) of water displacing oil from a water-wet matrix block exposed to water at one side and oil at the other. Counter-current flows can induce a stronger viscous coupling than during co-current flows leading to deceleration of the phases. Even as water displaces oil co-currently the saturation gradient in the block induces counter-current capillary diffusion. The extent of counter-current flow may dominate the domain of the matrix block near the water-exposed surfaces, while co-current imbibition may dominate the domain near the oil-exposed surfaces implying that one unique effective relative permeability curve for each phase does not adequately represent the system. As relative permeabilities are routinely measured co-currently it is an open question whether the imbibition rates in the reservoir (depending on a variety of flow regimes and parameters) will in fact be correctly predicted. We present a generalized two phase flow model based on momentum equations from mixture theory that can account dynamically for viscous coupling between the phases and the porous media due to fluid-rock interaction (friction) and fluid-fluid interaction (drag). These momentum equations effectively replace and generalize Darcy's law. The model is parameterized using experimental data from the literature.
We consider a water-wet matrix block in 1D that is exposed to oil on one side and water on the other side. This setup favors co-current SI. We also account for the fact that oil produced counter-currently into water must overcome the socalled capillary back pressure, which represents a resistance for oil to be produced as droplets. This parameter can thus influence the extent of counter-current production and hence, viscous coupling. This complex mixture of flow regimes implies that it is not straightforward to model the system by a single set of relative permeabilities, but rather relies on a generalized momentum equation model that couples the two phases. In particular, directly applying co-currently measured relative permeability curves gives significantly different predictions than the generalized model. It is seen that at high water-to-oil mobility ratios, viscous coupling can lower the imbibition rate and shift the production from less counter-current to more co-current as compared to conventional modelling. Although the viscous coupling effects are triggered by counter-current flow, reducing or eliminating counter-current production via the capillary back pressure does not eliminate the effects of viscous coupling that take place inside the core, which effectively lower the mobility of the system. It was further seen that viscous coupling can increase the remaining oil saturation in standard co-current imbibition setups.
Recently, the miscible CO2-EOR tertiary process used in the main pay zone (MP) of suitable reservoirs has broadened to include exploitation of the underlying residual oil zone (ROZ) where a significant amount of oil may remain. The objective of this study is to identify the ROZ and to assess the remaining oil in a brownfield ROZ by using core data and conventional well logs with probabilistic and predictive methods.
Core and log data from three wells located in the East Seminole Field in Gaines County, Texas, were used to identify the MP and ROZ in the San Andres Limestone, and to predict oil saturations. The core measurements were used to calculate probabilistic in-situ oil saturations within the MP and the ROZ as a function of depth. Well logs, in combination with core data and calculated saturations, on the other hand, were used to develop two expert systems using artificial neural networks (ANN); one to identify the ROZ and MP, and the other to predict oil saturation. These systems were also supported by a classification and regression tree (CART) analysis to delineate the rules that lead to classifications of zones.
Results showed that expert systems developed and calibrated by combining core and well log data can identify MP and ROZ with a success score of more than 90%. Saturations within these zones can be predicted with a correlation coefficient of around 0.6 for testing and 0.8 for training data. The analyses showed that neutron porosity and density well log readings are the most influential ones to identify zones in this field and to predict oil saturations in the MP and ROZ. To explain the relationships of input data with the results, a rule-based system was also applied, which revealed the underlying petrophysical differences between MP and ROZ.
This new predictive approach using machine learning techniques, could potentially address the challenges that previous studies have come up against in defining the ROZ within the formation and quantifying remaining oil saturations. The method can potentially be applied to additional fields and help reliably identify the ROZ and estimate saturations for future resource evaluations.
Føyen, T. L. (Dept. of Physics and Technology, University of Bergen) | Fernø, M. A. (Dept. of Physics and Technology, University of Bergen) | Brattekås, B. (The National IOR Centre of Norway, Dept. of Energy Resources, University of Stavanger)
Spontaneous imbibition is a capillary dominated displacement process where a non-wetting fluid is displaced from a porous medium by the inflow of a more-wetting fluid. Spontaneous imbibition strongly impacts waterflood oil recovery in fractured reservoirs and is therefore widely studied, often using core scale experiments for predictions. Decades of core scale experiments have concluded that spontaneous imbibition occurs by a uniformly shaped saturation front and that the rate of imbibition scales with square root of time. We use emerging imaging techniques to study local flow patterns and present new experimental results where spontaneous imbibition deviates from this behavior.
The imbibition rate during early stages of spontaneous imbibition (the
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 (
Smalley, P. C. (Imperial College London) | Muggeridge, A. H. (Imperial College London) | Dalland, M. (Norwegian Petroleum Directorate) | Helvig, O. S. (Norwegian Petroleum Directorate) | Høgnesen, E. J. (Norwegian Petroleum Directorate) | Hetland, M. (Norwegian Petroleum Directorate) | Østhus, A. (Norwegian Petroleum Directorate)
This paper presents an improved approach for rapid screening of candidate fields for EOR and estimation of the associated incremental oil recovery, and the results of applying it systematically to oil fields on the Norwegian Continental Shelf (NCS), an area that already has a high average recovery factor (47%). Identifying, piloting and implementing new improved recovery methods within a reasonable time is important if substantial remaining oil volumes on the NCS are not to be left behind.
The approach uses up-to-date screening criteria, and has more sophisticated routines for calculating screening scores and incremental oil recovery compared to previous published methods. The EOR processes screened for are: hydrocarbon miscible and immiscible WAG, CO2 miscible and immiscible WAG, alkaline, polymer, surfactant, surfactant/polymer, low salinity, low salinity/polymer, thermally activated polymers and conventional near well gel treatments. Overall screening scores are derived from sliding-scale scores for individual screening criteria, weighted for importance, and with the ability to define non-zero scores when non-critical criteria are outside their desired range, so avoiding the problem of processes being ruled out completely even though rock or fluid properties are only marginally outside the threshold of applicability. Incremental recoveries are estimated taking into account the existing recovery processes in the field and are capped by theoretical maximum recovery factors derived from theoretical/laboratory values for displacement and sweep. The methodology calculates the expected increment (and uncertainty range) for each EOR process and the increments for the top three compatible process combinations.
The methodology was implemented in a spreadsheet-based tool that allowed multiple fields to be screened and the results compared and evaluated. The new tool was used to estimate the potential EOR opportunity for 53 reservoirs from 27 oil fields on the NCS. The results indicate a mid case EOR technical potential of 592 million standard cubic metres (MSm3) with a low- to high case range of 320-860 MSm3. The most promising processes are low salinity with polymer, surfactant with polymer, and miscible hydrocarbon and CO2 gas injection. Some field clusters were identified that could provide economies of scale for such processes.
The EOR screening study has enabled the Norwegian Petroleum Directorate to advocate EOR-technology studies, including pilots, in specific regions or fields. Such pilots will play an important role in verifying process feasibility and narrowing the uncertainty range for incremental recovery potential.
The wettability of tight reservoir rock plays a critical role in affecting relative permeability and in turn oil recovery. However, the link between wettability and its effects on oil recovery remains poorly understood, and the potential to boost oil recovery by varying the wettability has not been fully explored. This work was an attempt to conduct a systematic experimental study to improve our understanding of wettability of tight oil reservoirs and the mechanisms of its alteration on oil recovery improvement. Contact angles of individual rock-forming minerals and reservoir rock samples were first measured in brines with different salinities. Then the minerals were aged separately with a medium crude oil with sufficient polar components to investigate their tendency for wettability alteration. As well, oil and water distributions inside tight core samples were scanned by a synchrotron-based computed tomography scanner. Contact angle measurements for all minerals and reservoir rocks showed initial water-wetting behavior. After aging with crude oil for over two months, polar components from the oil adsorbed onto the solid surfaces to alter their wettability to less water wet. Consequently, this wettability alteration contributed to oil and water redistribution and saturation change in reservoir cores.
The experimental findings suggested that the wettability in tight reservoirs is a strong function of rock mineralogy, formation fluid properties, and saturation history. Preliminary numerical simulation revealed how rock wettability alteration could contribute to improved oil recovery through waterflooding.
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.
Lu, Xueying (The University of Texas at Austin) | Lotfollahi, Mohammad (The University of Texas at Austin) | Ganis, Benjamin (The University of Texas at Austin) | Min, Baehyun (Ewha Womans University) | Wheeler, Mary F. (The University of Texas at Austin)
CO2 capture and sequestration in subsurface reserves are expensive processes. Flue gas can be directly injected into the oil and gas reservoirs to eliminate the cost of CO2 separation from power plant emissions and simultaneously enhance hydrocarbon production that may offset the cost of gas compression. However, gas injection in subsurface resources is often subject to poor volumetric sweep efficiency caused by low viscosity and low density of the injection fluid and formation heterogeneity. This paper aims to study gas mobility control techniques of water alternating gas (WAG) and foam in Cranfield and characterize key operational parameters to the success of the process. A coupled compositional flow and geomechanics simulator, IPARS, is used to accurately simulate the underlying physical processes, with a field scale numerical model, over the desired time-span. We map flow patterns to identify risks of leakage due to interactions of viscous, gravitational, and capillary forces. A hysteretic relative permeability model enables modeling local capillary trapping. Foam mobility control technique is examined to investigate the eminent level of CO2 capillary trapping by an implicit texture foam model. The WAG and foam injection process are optimized for the number of cycles, length of the cycles using the genetic algorithm (GA) in the UT optimization toolbox. The coupled flow-mechanics model can detect the effect of the plausible interaction of geomechanics and fluid flow on CO2 plume extension. Field-scale simulations indicate that during WAG and foam processes, the oil recovery increased significantly and CO2 storage increased by 30% and 49% of during the injection spam compared to continuous gas flooding, respectively. Optimized foam process saved 25% water and surfactant consumption comparing to base case foam processes while achieving approximately the same oil recovery.
Mukherjee, Biplab (The Dow Chemical Company) | Patil, Pramod D. (The Dow Chemical Company) | Gao, Michael (The Dow Chemical Company) | Miao, Wenke (The Dow Chemical Company) | Potisek, Stephanie (The Dow Chemical Company) | Rozowski, Pete (The Dow Chemical Company)
Steam injection is a widespread thermal enhanced oil recovery (EOR) method to increase oil mobility. The introduction of steam heats the reservoir, ultimately lowering oil viscosity and in turn enhancing heavy oil recovery. In the steam injection process, recovery of oil is limited by steam channeling due to reservoir heterogeneities. Early breakthrough implies that there is a large consumption of steam and incomplete reservoir drainage. Injection of surfactant with steam and a non-condensable gas such as nitrogen can generate foam
In this paper, a systematic approach to screen surfactants for field applications at high temperature is presented. A feasibility test was conducted with the surfactant formulation (HSF-X) at target reservoir conditions to understand the thermal stability and adsorption behavior of the surfactant. Investigation found that the thermal decomposition and adsorption of the surfactant on sandstone rock under static conditions was mimimum at 200°C. In core flood testing conducted using silica sand and natural sandstone cores, foam generated by injecting N2 and HSF-X surfactant solution was able reduce steam mobility between 40 to 100 times at 100°C and 10 to 15 times at 200°C more compared to steam mobility in the absence of the foam. Finally oil recovery experiments at 200°C using silica sand cores indicated the ability of the HSF-X surfactant to foam in the presence of oil and enhance recovery of oil (a +20% increase in the original oil in place (OOIP) was observed).