Solvent injection has emerged as a recovery technique in low pressure and shallow heavy oil reservoirs in cold systems or in combination with steam in steam-based thermal processes. The performance of solvent-based processes strongly depends on the rate of mass transfer in the boundary layer on the edge of solvent and/or steam chamber. Therefore, understanding of the mass transfer phenomena is required for realistic prediction of the performance of solvent-based or solvent-assisted processes. This study was designed to investigate the capillarity and aqueous phase saturation effects on the rate of mass transfer occurring in the boundary layer on the edge of the solvent chamber. In this study, a new experimental approach was designed and developed to eliminate any disturbance in the boundary layer to experimentally simulate the gravity drainage process in vapor extraction process at two different drainage heights. The porous media and oil-solvent characteristics required for history matching study were determined by measuring the capillary pressure and pore size distribution of sand packs, as well as conducting a complete phase behavior study to determine the properties of the oil-solvent system in a wide range of solvent concentrations. Total number of 12 experiments was conducted in three different sandpacks with different pore size distributions, but similar range of permeabilities (i.e., 5.1-6.5 D) to investigate the effect of capillary forces on the mass transfer phenomena.
Conducted analytical and numerical modeling showed that the effective diffusion coefficient was in the range of 4.91×10-8-1.10×10-5 cm2/s. In absence of immobile water saturation, effective diffusion coefficient was in the range of 4.91×10-8-7.89×10-6 cm2/s. In presence of immobile of aqueous phase saturation, the effective diffusion coefficient varied between 2.96×10-6 and 1.10×10-5 cm2/s. The comparison between the calculated effective diffusion coefficients and reported molecular diffusion in literature by different researchers confirmed that the velocity-dependent term in convective dispersion does not play a major role at higher capillarities in heavy oil systems, i.e., lower permeability range compared to other studies (i.e., >100 D). This study highlights the need for selection of a realistic mass transfer coefficient for the simulation of the performance of the solvent injection processes.
Combination of complex sedimentation environment and carbonates’ diagenetic alterations render carbonate reservoirs to be very heterogeneous and often naturally fractured. Heavy oil trapped in carbonate reservoirs worldwide is estimated to be over 255 billion cubic meters. The drastic differences in flow and storage capacity of the fracture and matrix networks trigger the need for larger volumes of steam to be injected to produce one cubic meter of heavy oil production, making the application of thermal recovery processes in these reservoirs to be more economically challenging and highly energy intensive.
Recovery of heavy oil from naturally fractured reservoirs is weakly controlled by viscous forces and mostly controlled by capillary and gravity forces, in addition to convection and conduction heat transfer. This makes proper representation of fracture and matrix characteristics to be of paramount importance to the reliability of modeling thermal recovery processes.
This paper discusses the effect of variable fracture characteristics including fracture typing, spacing, and apertures on the performance of dual permeability models under different thermal recovery processes. Further, the paper demonstrates the necessity to characterize partially mineralized fractures and shows its effect on thermal conductivity from fractures to matrix blocks.
The effect of wettability on the recovery process is also discussed. Oil recovery in fractured reservoirs is highly influenced by imbibition process which is most effective under strong water wetness. The paper addresses the performance under water, oil and mixed wettability conditions. Furthermore, the paper shows that proper representation of capillary pressure hysteresis could cause considerable change in oil recovery performance. The modeling work in this paper helps to curtail any extra optimism that may originate from wrongly characterized dual permeability models. Finally, and in case reservoir characteristics are not well determined then forecasting based on uncertainties of reservoir characteristics should give operators a way to estimate the risk involved in the exploitation process of the carbonate resources.
Co-injection of solvent with steam in SAGD has shown promise for enhancing oil rates as well as in reduction of energy and water consumption. Modeling and optimization of hybrid steam-solvent recovery processes with commercial numerical simulators can be very time consuming. In addition, the complex interaction of heat and solvent effects in mobilizing heavy oil at the vapour chamber boundary are often difficult to ascertain from the numerical models. Semi-analytical mathematical models can provide insight into the physics of the processes and may be used to estimate production rates and thermal efficiency in much less time.
In this study, an unsteady-state semi-analytical model was developed to predict the oil flow rate in the steam-solvent assisted recovery process. The model assumes a curved interface with transient temperature and solvent distribution in the mobile zone. It also accounts for transverse dispersion and concentration-dependent molecular diffusion for solvent distribution. The oil flow rate and interface profile are predicted at each time in an iterative fashion. The results show that the coefficient of diffusion-concentration function significantly affects the solvent penetration depth and its distribution. The semi-analytical model was able to predict oil production rates using different solvents co-injected with steam, in agreement with reported experimental data.
The proposed model reveals the complex interaction of heat and solvent solubility and diffusion as they affect mobilization and production of viscous oil. This model may be used to find the optimal operation parameters for the process over a range of different reservoir qualities and pressures, in a very time-efficient manner. The final outcome may lead to an efficient design of a steam-solvent recovery process that utilizes less water and reduces the amount of energy and gas emissions per barrel of oil produced.
Albardisi, Tareq (Schlumberger) | Akhmetov, Roustam (Schlumberger) | Sanderson, Martin (Schlumberger) | Adly, Essam (Schlumberger) | Escamilla, Barton (Schlumberger) | Andreasen, Greg (Schlumberger) | Noureldin, Ali (Schlumberger) | Al Habsy, Hilal (Schlumberger)
A heavy oil field, located in south-central Oman with unconsolidated sandstone reservoirs represents many drilling challenges. Past drilling with conventional mud motors in the field was associated with many drilling risks, including poor wellbore quality, difficulty steering, inadequate hole cleaning, and differential sticking. These risks resulted in extra correction trips, lost-in-hole bottomhole assemblies, sidetracking, and redrilling entire sections.
The field’s current development plan is based on the factory drilling concept, which is driven by the number of wells that are required to be delivered in a given year. This requirement places a great amount of importance on drilling time. The average time from spud to spud in the field is 8 to 9 days; any additional trips have a large impact on the total number of wells delivered. In addition, due to the nature of the heavy oil sandstone reservoir, steam injection is required to enhance oil recovery. It is therefore critical to place the lateral hole section of the well in the center of the target corridor to avoid early breakthrough. To compound this, the fluvial nature of the reservoir, tight surface location constraints, and shallow reservoir true vertical depths (TVDs) have added to directional complexity.
To address the main technical challenges of directional assurance and greater drilling efficiency, the operator and service company explored alternative ways of drilling the 8.5-in. reservoir hole section, and this hole section was be the focus of our analysis.
The learning curve experienced in finding an answer for the technical challenges of directional control and drilling efficiency can be broken down to four distinct phases:
Extensive data gathering and log analysis provided a better understanding of the main issues and ultimately led to the root cause. The analysis provided a clear solution, which was that a high-build-rate-capable RSS was needed to overcome the directional tendencies and deliver the planned well trajectory to the final total depth (TD) in one run to reduce the average well time.
Lu, Chuan (China University of Petroleum-Beijing) | Liu, Huiqing (China University of Petroleum-Beijing) | Liu, Qian (Exploration and Development Research Institute of Liaohe Oilfield Company) | Lu, Keqin (No.1 Oil Plant of Huabei Oil Field) | Wang, Limei (No.1 Oil Production Plant of Huabei Oil Field)
Steam Assisted Gravity Drainage (SAGD) is widely used as an in-situ technology to recover heavy oil and bitumen. But due to serious heat losses, large energy requirements and enormous CO2 emissions, pure SAGD may not be sufficiently efficient to allow economical production.
The main objective of addition of viscosity reducer is to couple viscosity reduction capability of heat and surfactant. It strengthens the formation of emulsions of O/W type that have much lower viscosity than the oil from which they are formed, and enhances oil production under the same amount of steam to make the thermal process more profitable. With regard to the non-condensable gas, its distribution and movement is essential for the expansion of the steam chamber.
In this paper, the performances of a set of selected viscosity reducers under high temperatures are firstly evaluated. Then based on a high temperature and high pressure two-dimension physical model, different injection processes are conducted to study the separate and combined effect of nitrogen and viscosity reducer on the vertical and horizontal expansion rates of steam chamber. The results show that the injection of nitrogen helps the steam chamber expand more quickly in the horizontal direction. And the combination of viscosity reducer and nitrogen makes the steam chamber expand more quickly than the pure SAGD and Nitrogen-SAGD processes. The following sand pack physical models are conducted to further investigate the mechanisms of viscosity reducer and nitrogen in porous media, such as the steam profile correction relying on the blocking capacity of emulsions, heat loss reduction and the combination effect of gas expansion and viscosity reducer on the displacement of residual oil. In addition, numerical simulations are conducted to demonstrate the feasibility of SAGD assisted by viscosity reducer and nitrogen in Du 84 ultra-heavy oil reservoir. Besides optimizing operation parameters, such as nitrogen steam ratio, effective nitrogen injection volume, interval time between viscosity reducer injection and nitrogen injection, the study results show the effect of this technology on the improvement of thermal oil recovery.
In summary, this study is beneficial for the application of viscosity reducer and nitrogen in the process of SAGD.
Alkali metal silicides have ability to enhance oil recovery in a variety of light, medium and heavy oil reservoirs. These chemicals, which include the silicides of sodium (Na), potassium (K) and lithium (Li), are free-flowing granules or very fine powders that are applied downhole in hydrocarbon dispersions. When introduced into a formation through an appropriate non-aqueous carrier fluid, these materials rapidly react with the water in the reservoir pore space, releasing hydrogen gas and heat, and converting into alkali silicates. The silicide-water reaction combined with the flooding process provides multiple mechanisms in the reservoir to enhance oil recovery. Enhanced oil recovery mechanisms include: energy addition through the generation of hydrogen; oil viscosity reductions due to hydrogen solubilization, temperature increase and solvent dilution from the carrier fluid; interfacial tension reduction due to in-situ surfactant generation from interaction of the crude oil organic acids in the reservoir oil with the alkalinity from the produced silicates; and potential improvement of water wettability in carbonate reservoirs. This one chemical combines the effects of thermal, drive energy and chemical mechanisms.
In this work, a field-scale numerical simulation study was conducted to investigate the feasibility of cyclically injecting an alkali metal silicide into the wormhole structures of a post CHOPS (cold heavy oil production with sand) reservoir. The Computer Modeling Group’s (CMG) STARS simulator was used to perform the simulations; the model consists of six vertical wells with wormhole structures developed using proprietary wormhole growth models that are based on actual field production histories from a representative CHOPS field in Canada (the Lloydminster, Alberta and Saskatchewan region). Multiple simulation cases were run to investigate the effects of injected cycle volume, cycle time, injection rate and silicide concentration. A sensitivity analysis was performed on parameters affecting the slurry model and dispersion rates of the silicide in the reservoir. The preliminary economics of the process were calculated and used to identify an optimized and cost-effective injection strategy, which can subsequently be used as a basis to design a field trial application.
The study results showed that the cyclic injection of sodium silicide in a post CHOPS reservoir can in fact improve the recovery of oil in place. The study shows that the predominant recovery mechanism is likely the pressure maintenance of the reservoir that provides energy for continued oil production. This, coupled with secondary oil viscosity reductions, enable the cyclic injection of silicide to increase production for an additional 5 to 10 years, thereby adding 25 to 50% to recoverable reserves under favorable economics. This paper discusses the impacts of the in situ generation of heat, hydrogen and alkali silicate for post CHOPS augmentation and summarizes the key findings of the simulation study and economic modeling.
Cyclic steam stimulation (CSS) is a commercial in situ recovery method that involves injecting steam into formations at high pressure to reduce the viscosity of heavy oil and bitumen. The injection pressure is typically above the reservoir fracture pressure to induce fractures, which can improve reservoir permeability and fluid mobility. Geomechanics and heterogeneities near a well significantly affect reservoir fracturing, particularly under thermal conditions. In addition, oversimplified descriptions of fracture geometry may fail to represent actual reservoir performance. Thus modeling near-well flow effects coupled with geomechanics is essential for detailed large-scale thermal simulations with fractures. Conventional methods have exhibited limitations in capturing interactions among wellbore/near-well flow, geomechanics, and fluid flow during CSS development. Therefore, flow/stress/near-well flow coupling under different fracture geometries is investigated in this study.
A facies-controlled geostatistical model is first constructed for a Cold Lake reservoir to obtain more reliable results. A fully coupled model is further generated from this geological model. After local grids near wells are refined, we construct different fracture geometries by changing the fracture length and direction. In this study, uncertainty analyses on fracture geometry near the vertical wells are performed. The simulation results show that omitting geomechanics and wellbore modeling increases oil recovery. Moreover, oversimplified fracture geometry with simple planes overestimates an oil rate. Furthermore, fractures with complex geometries and geomechanics exhibit high conductivity and provides effective channels for steam and bitumen but at the same time, it may cause steam channeling and decrease the efficiency of steam injection.
Reservoir recovery processes are complex and typically entail several physical or chemical mechanisms. Polymer flooding has often been depicted to be dominated by one mechanism: water viscosification reduces the mobility ratio, and stabilizes the displacement front to increase oil recovery. Increasingly though the contribution of mechanisms other than water viscosification is becoming understood. This paper points out two novel insights into polymer flooding: (1) the intrinsic value of the polymer is likely being overestimated and (2) the practice of operating the polymer flood with incomplete voidage replacement may indeed be optimal. The conversion of a conventional waterflood to a polymer flood entails significant injectivity reduction, up to 50% or more. The maintenance of complete voidage replacement (VRR = 1) would thus require an increase in the number of injectors, or a reduction of total production rate or both. As both interventions reduce the economic returns, most projects operate with incomplete voidage replacement (VRR < 1). We have previously reported that a VRR < 1 improves the waterflood response of heavy oil reservoirs. Thus using the VRR = 1 waterflood as the comparison benchmark to the polymer response may overestimate the value of viscosification – the intrinsic value of the polymer. To quantify this, we have performed numerical simulations of polymer flooding for VRRs ranging from 0.4 to 1.4, deconvolving the relative contributions of the viscosification and VRR < 1 mechanisms. We observe that a polymer flood operated with VRR > 1 (above the oil bubble point) underperforms a polymer flood with a VRR < 1 by as much as one third. We conclude that the intrinsic value of the polymer is overestimated.
The production of gaseous sulfur-containing species during the steam-assisted recovery of heavy oil and bitumen have important consequences for both economics and safety. Factors such as the effects of mineral matrices require laboratory data to produce accurate models. To study mineral effects on gas production we studied a well-characterized oil-containing core and the isolated crude oil from that core. The samples were run at 250-300°C in the continued presence of liquid water for 24 hours. The reaction products of all experiments include gases, oil flotate, oil sinkate, water-soluble products, and water- insoluble residues. All reaction products were studied with a variety of analytical techniques, including FTIR spectroscopy, chromatographic fractionation (SARA analysis), GC-MS, pyrolysis GCMS and GC-FPD/TCD. These techniques were applied to whole oil, maltenes and asphaltene fractions. Physical properties including viscosity and density were also measured. Our data provide insights into the physical and chemical consequences of steam assisted recovery of heavy oils and bituments from sedimentary rock reservoirs and reveal that geological and geochemical context is an essential consideration.
The depositional environment at Statoil’s Leismer SAGD demonstration project is dominated by a fluvial-deltaic system with complex geological features which present challenges for SAGD operations. An efficient monitoring tool that could combine geoscience data with production knowledge is vital for optimizing SAGD operational strategies. Time lapse (4D) seismic survey is one such monitoring tool. It can be integrated with wells and production data to prepare and optimize operational strategies. The pattern of growth of steam chamber is critical for well performance optimization. Steam chamber development dictates which reservoir areas are using heat efficiently and contributing to drainage of bitumen and increased production.
At Leismer, two 4D monitor seismic surveys have been conducted since the start of operations. The 1st monitor was acquired in 2012 to observe one year of SAGD performance and the 2nd monitor in 2013 to observe the performance after 2 years of operation. These surveys have been used to identify challenges to maximizing well pair productivity. Of primary concern is the effective distribution of steam along the entire horizontal section of the SAGD well pair. Other 4D monitoring benefits include, monitoring subcools with respect to reservoir heterogeneities, bottom water communication, steam chamber coalescence, baffle or barrier to steam chamber growth identification.
In this study, examples are presented to show how combining production and 4D seismic data has contributed to well pair optimization. Communication with bottom water in the early stages of SAGD, while rare, occurred in specific Leismer well pairs – analyses of production data combined with 4D seismic data helped identify steam loss into bottom water which drove steam injection strategy and improved well productivity. Another Leismer example shows how 4D seismic has been used to confirm a low reservoir roof at the toe of a particular well pair. This knowledge drove a change in injector well completion to optimize production. In the final example, it is shown how 4D seismic has helped analyze and confirm well conformance (heat distribution along SAGD well pairs) which is critical for uniform steam chamber development.
Based on Statoil’s Leismer experience of applying results of 4D seismic analyses for well optimization, it can be concluded that 4D seismic has proven to be a very useful and value adding monitoring tool.