Feali, Mostafa (University of New South Wales) | Pinczewski, Wolf (University of New South Wales) | Cinar, Yildiray (University of New South Wales) | Arns, Christoph H. (University of New South Wales) | Arns, Ji-Youn (University of New South Wales) | Francois, Nicolas (Australian National University) | Turner, Michael L. (Australian National University) | Senden, Tim (Australian National University) | Knackstedt, Mark A. (Digitalcore)
Arns, SPE, University of New South Wales; M. Turner and T. Senden, SPE, Australian National University; and N. Francois, Australian National University, and M. Knackstedt, SPE, Digitalcore Summary It is now widely acknowledged that continuous oil-spreading films observed in 2D glass-micromodel studies for strongly water-wet three-phase oil, water, and gas systems are also present in real porous media, and they result in lower tertiary-gasflood residual oil saturations than for corresponding negative spreading systems that do not display oil-spreading behavior. However, it has not yet been possible to directly confirm the presence of continuous spreading films in real porous media in three dimensions, and little is understood of the distribution of the phases within the complex geometry and topology of actual porous media for different spreading conditions. This paper describes a study with high-resolution X-ray microtomography to image the distribution of oil, water, and gas after tertiary gasflooding to recover waterflood residual oil for two sets of fluids, one positive spreading and the other negative spreading, in strongly water-wet Bentheimer sandstone. We show that, for the positive spreading system, oil-spreading films maintain the connectivity of the oil phase down to low oil saturation. At similar oil saturation, no oil films are observed for the negative spreading system, and the oil phase is disconnected. The spatial continuity of the oil-spreading films over the imaged volume is confirmed by the computed Euler characteristic for the oil phase.
Normal pressure/volume/temperature (PVT) analysis is based on a fundamental assumption that there is no potential difference between the gas and liquid phases. The nanometer pore throats in unconventional reservoirs could impose a phase capillary pressure up to 1,000 psi. Therefore, the observed oil viscosity and bubble point pressure (Pb) in an unconventional oil reservoir are substantially lower than those reported by the PVT lab. Such reductions are further aggravated by the compaction effect and then become variable with pressure depletion. In this work, a set of non-linear fugacity equations was constructed by bringing capillary pressure in with the phase equilibrium equations.
The corresponding PVT reports for 14 Bakken fluid samples were recalibrated by combining the newly developed non-linear fugacity equations and the pore throat reduction imposed by compaction effects. The resultant PVT tables help clarify all the inconsistent PVT observations. Examples are presented to demonstrate the significance of such PVT corrections.
The corrected PVT tables were used in the Bakken reservoir simulation model and successfully resolved not only the inconsistent gas/oil ratio (GOR) issue between the model and real production data, but also substantially facilitated the history match and widened the optimal operational pressure window.
A series of studies were completed to address the combined impact of the capillary pressure and compaction on Bakken reservoir fluid properties. The Pb could be reduced in a range from hundreds to over 1,000 psi, compared to the corresponding lab PVT report. Such reduction is more severe in the lower formation permeability and solution GOR scenarios. Furthermore, oil density and viscosity could also be reduced by up to 10% due to the lighter components migrating to the oil phase. This study reveals the cause of the delayed GOR increase and the strange stepwise GOR increases observed in unconventional oil reservoirs.
This new understanding of the PVT property variation in an unconventional oil reservoir optimizes the operations procedure and will permit more reliable performance forecasts.
Jyotsna Sharma, SPE, R.G. Moore, SPE, and Raj Mehta, SPE, University of Calgary Summary Steam-assisted gravity drainage (SAGD) is a commercially viable recovery method for oil sands of Athabasca used where other methods have been unsuccessful. In one variation of SAGD, a small amount of a noncondensable gas is added to the injected steam to maintain pressure in the chamber while using the energy in place, reducing steam consumption and providing thermal insulation from overburden heat losses. The role of gas during steamgas co-injection processes, in terms of its effects on chamber development, bitumen flow rates, and heat losses, is not fully understood, and therefore is the main focus of this work. A new analytical model for gas injection in SAGD is derived, taking into account the three-phase flow of gas, oil, and water in the reservoir. The analytical theory is used to predict the fluid flow rates as well as phase mobility, relative permeability, and saturation profiles in the mobile oil region. The theoretical results are replicated by fine-grid numerical simulations. Methane was used as the noncondensable gas for the purpose of this study because it is the main solution gas in most reservoirs. It is, however, believed that the findings of this study are equally applicable to other noncondensable gases such as nitrogen, air, helium, and others. Fine-grid numerical simulations were performed to gain a visual understanding of gas distribution in a SAGD chamber and its effect on in-situ steam quality, overburden heat losses, phase saturations, and fluid-flow rates. The results of the analytical and numerical study reveal that methane co-injection with steam is in general unfavorable in a SAGD operation. The injected methane tends to accumulate at the steam condensation front, which lowers the heat transfer rate of steam to the adjacent oil, resulting in lower oil production rates and slower growth of the chamber.
In the current paper, a mathematical model to describe the nanoparticles transport carried by a two-phase flow in a porous medium is presented. Both capillary forces as well as Brownian diffusion are considered in the model. A numerical example of countercurrent water-oil imbibition is considered. We monitor the changing of the fluid and solid properties due to the addition of the nanoparticles using numerical experiments. Variation of water saturation, nanoparticles concentration and porosity ratio are investigated.
Multiphase flow in pipe has been intensively investigated since the oneset of oil and gas transportation by pipelines. As flow assurance problems keep arising in recent years, pipeline design solutions are desired for multi-phase flow system. The algorithms have widely guided the design of stream transportation from offshore well head to onshore terminal or platform. Operators would always seek cutting platform number or shut-in producing marginal field whose reserves cannot justify the construction cost. An accurate design of multiphase flow pipeline system is by all means demanded.
Traditional studies focus on gas-oil two-phase flow by deriving empirical or semi-empirical correlations that fit the experimental data. This study investigates a gas-oil-water three-phase pipe flow system. Starting from the momentum and mass conservation equations, force balance, and interaction relationships between different phases, we developed analytical solutions to estimate the pressure drop for stratified flow regime. This general approach can be applied to any gas-oil-water flowing systems. It provides a solid base for nodal analysis, pressure drop calculation for multiphase flow, artificial lift evaluation, etc. to help design and optimize production system. This work can be particularly useful for steady-state distance transportation.
Feali, Mostafa (U Of New South Wales) | Pinczewski, Wolf Val (U. of New South Wales) | Cinar, Yildiray (U. of New South Wales) | Arn, Christoph (U. of New South Wales) | Arns, Ji-Youn (Australian National Univ.) | Francois, Nicolas (Australian National Univ.) | Turner, Michael (Digital Core Laboratories Pty Ltd) | Senden, Tim | Knackstedt, Mark
It is now widely acknowledged that continuous oil spreading films observed in two-dimensional glass micro-model studies for strongly water wet three-phase oil, water and gas systems are also present in real porous media and result in lower tertiary gas flood residual oil saturations than for corresponding negative spreading systems which do not display oil spreading behavior. However, it has not been possible to directly confirm the presence of spreading films in real porous media in threedimensions and little is understood of the distribution of the phases within the complex geometry and topology of actual porous
media for different spreading conditions. This paper describes a preliminary study using high resolution X-ray microtomography to image the distribution of oil, water and gas after tertiary gas flooding to recover waterflood residual oil for two set of fluids, one positive spreading and the other negative spreading, for strongly water wet conditions in Bentheimer sandstone.
We show that for strongly water-wet conditions and a positive spreading system the oil phase remains connected throughout the pore space and results in a low tertiary gas flood residual oil saturation. The residual oil saturation for the corresponding negative spreading system is significantly higher and this is shown to be related to the absence of oil films in this system. The presence of films for positive spreading systems and the absence of such films for negative spreading systems is further confirmed by the computation of the Eurler characteristic for each phase.