In recent years, the Cyclic Solvent Injection (CSI) process has shown to be a promising method for enhanced heavy oil recovery in Canada. CSI laboratory studies work for only 2 to 3 cycles due to low incremental oil in subsequent cycles. However, in field pilots the CSI keeps operational after many years. This study intends to capture the full production mechanisms responsible of heavy oil production in CSI to better understand the phenomena in field applications.
A physical sandpack model was used to test the CSI response. The sandpack was saturated with live heavy oil of 7900 mPa.s viscosity at 24 ° C, and primary production was run. Five CSI tests were then conducted to simulate the performance under the gravity effects. The experiments were conducted in a horizontal and vertical mode injection respectively at high and low-pressure depletion rates using 70 mol % CH4 and 30 mol % C3H8 solvent mixture. The sandpack was Computed Tomography (CT) scanned after every cycle to provide information about the gas and oil saturations evolution.
When CSI was run on the horizontal core, the incremental oil recovery was negligible for both slow and fast drawdown rates. When the sandpack was vertically flipped and rapidly produced, the three CSI cycles exhibited higher recover, and similar incremental recovery per cycle. This result indicated that even at high drawdown pressures, gravity segregation can effectively maximize the cross-flow mixing between solvent and heavy oil to penetrate the un-swept areas.
The results of this study demonstrate the importance of gravity drainage in the CSI process, and the relative significance of gravity forces on successful oil recovery rates. The results of this study illustrate the limitations of previous horizontal laboratory tests and show an improved test configuration for modeling and prediction of the improved response observed in CSI pilots.
Steam injection is a widely used oil-recovery method that has been commercially successful in many types of heavy-oil reservoirs, including the oil sands of Alberta, Canada. Steam is very effective in delivering heat that is the key to heavy-oil mobilization. In the distant past in California, and also recently in Alberta, solvents were/are being used as additives to steam for additional viscosity reduction. The current applications are in field projects involving steam-assisted gravity drainage (SAGD) and cyclic steam stimulation (CSS).
The past and present projects using solvents alone or in combination with steam are reviewed and evaluated, including enhanced solvent SAGD (ES-SAGD) and liquid addition to steam for enhancing recovery (LASER). The use of solvent in other processes, such as effective solvent extraction incorporating electromagnetic heating (ESEIEH) and after cold-heavy-oil production with sand (CHOPS), are also reviewed. The theories behind the use of solvents with steam are outlined. These postulate additional heavy-oil/bitumen mobilization; oil mobilization ahead of the steam front; and oil mobilization by solvent dispersion caused by frontal instability. The plausibility of the different approaches and solvent availability and economics are also discussed.
Ouled Ameur, Zied (Cenovus Energy Inc) | Kudrashou, Viacheslau (Texas A&M Engineering) | Nasr-El-Din, Hisham A. (Texas A&M University) | Forsyth, Jeffrey (nFluids Inc) | Mahoney, John (Mahoney Geochemical Consulting) | Daigle, Barney (AkzoNobel)
The acidizing of sour, heavy-oil, weakly consolidated sandstone formations under steam injection is challenging because of fines migration, sand production, inorganic-scale formation, corrosion issues, and damage caused by asphaltene precipitation associated with these sandstone formations. These and other similar problems cause decline in the productivity of the wells, and there is a recurring need to stimulate them to restore productivity. The complexity of sandstone ormations requires a mixture of acids and several additives, especially at temperatures up to 360°F, to accomplish successful stimulation. Three treatments were tested on a horizontal well in the field: hydrochloric acid (HCl); Chelating Agent B, a high-pH chelant; and Chelating Agent A, or glutamic acid N,N-diacetic acid (GLDA). The first two treatments with 15 wt% HCl and high-pH (pH=10) Chelating Agent B produced results below expectations. The third treatment using GLDA was successful, and the well productivity increased significantly. The field treatment with GLDA included pumping the treatment fluid, which was foamed to create proper rheological characteristics and a better-controlled pumping process. The treatment fluids were displaced into the formation by pumping produced water and were allowed to soak for 6 hours. In this paper, we evaluate the field applications of GLDA using geochemical modeling, production data, and analysis of well-flowback fluids after the field treatments.
Bao, Yu (Research Institute of Petroleum Exploration & Development, CNPC) | He, Liangchen (Liaohe Oilfield Company Ltd, Petrochina) | Lv, Xue (Sino-Pipeline International Company Ltd.) | Shen, Yang (Research Institute of Petroleum Exploration & Development, CNPC) | Li, Xingmin (Research Institute of Petroleum Exploration & Development, CNPC) | Liu, Zhangcong (Research Institute of Petroleum Exploration & Development, CNPC) | Yang, Zhaopeng (Research Institute of Petroleum Exploration & Development, CNPC)
The Orinoco heavy oil belt in Venezuela is one of the largest extra-heavy oil resources in the world. It has become a major goal for the unconventional oil exploitation in these years. Now, the most common production method is to use the horizontal well cold production without sand. It is an economic and commercial process, and with the reservoir of this area have high initial gas to oil ratio (GOR), porosity and permeability with unconsolidated sand. However, after several years' production, the oil rate draws down quickly caused by the reservoir pressure drops; the key challenge of cold production is that the recovery factor (RF) tends to be only between 8% and 12%, implying that the majority of the oil remains in the oil formation. It is necessary to develop viable recovery processes as a follow-up process for cold production. Generally, steam based recovery method was widely used as a follow-up process for cold production. In this paper, steam fracturing (dilation) Cyclic Steam Stimulation (CSS) operation and Non steam fracturing (No dilation) CSS operation by using reservoir simulator is examined for a post cold production in extra heavy oil reservoir, in order to analyze the performance of the oil rate, cumulative steam-to-oil ratio (cSOR), steam depletion zone, greenhouse gas emission and some necessary parameters.
The key component of the steam fracturing (dilation) is the ability to inject high temperature and pressure steam into the formation to fracture the reservoir rock which in turn raises the rock permeability and mobilized the oil by lowering the visocisity. To compare the results of the dilation and no dilation CSS operation, this study reveal that due to the steam is injected into the reservoir by using the same cumulative cold water equivalent (CWE), the steam condensate; pressurized by steam vapour, fracture the formation. Dilation operation achieves higher oil rate, lower cSOR. The result also show that fraturing (dilation) of the reservoir during steam injection relieves the pressure which in turn lowers the steam injection pressure below the case where No dilation operation ouccurs.
ABSTRACT: Cyclic steam stimulation has become an important method for enhancing the recovery of heavy oil reservoir. Accurate prediction of changes in pore pressure and stress within the near wellbore region during the stimulation is of critical importance for wellbore stability and sand production analyses. However, cyclic steam stimulation is a complicated process which involves complex interactions among multiphase fluid flow, heat transfer and elastoplastic deformation of the formation rock. In this present work, we developed a fully coupled thermo-hydro-mechanical model for simulating the cyclic steam stimulation of heavy oil reservoirs. A three-phase, two-component formulation is employed for characterizing the flow of oil and water/steam within the pore space. Elastoplastic deformation of the heavy oil reservoir rock is treated with the Mohr-Coulomb model. In addition to thermal conduction, thermal convection is also considered due to the high permeability frequently featured by heavy oil reservoirs. Mathematical equations governing these coupled physical processes are discretized and solved with the finite element method in a fully coupled manner. Validations of the model against analytical solutions to some simple problems have been performed, which demonstrate the capability of the model to capture the coupling behavior between pore fluid flow, heat transfer and deformation of the reservoir rock. As an example of application, the model has been applied to simulate the cyclic stream stimulation performed in horizontal wells drilled in a heavy oil reservoir in the Bohai oilfield of China. The sizes of the heated zones as well as the stress, temperature and pore pressure distributions around the wellbore under different injection parameters were predicted and some implications for wellbore stability have been presented.
Heavy oil is abundant around the world. However, it is hard to be extracted from the reservoir due to the extremely high viscosity at the reservoir temperature. Various thermal recovery methods have been proposed for significantly reducing the viscosity of heavy oil and realize economic production, among which Cyclic steam stimulation (CSS) has become an extremely successful and widely used technique for enhancing recovery of heavy oil (Vittoratos et al., 1990). CSS generally involves several days of injection of steam into a well drilled in the heavy oil reservoir, followed by a short period of soaking process and a long period of hot production of the heated oil from the same well. This injection-soaking-production cycle is usually repeated many times, and the amount of steam injected into the reservoir usually increases from one cycle to the next in order to extend the unheated zone.
Permeability enhancement of oil sands during SAGD, a gravity drainage process, is desirable to minimize start-up time and improve overall recovery efficiency. High pressure cold water injection may be used as a stimulation process where water is injected into a SAGD well pair at high pressure and limited volume to distort the sand texture and enhance permeability or break thin impermeable interbeds impeding the hot fluid movement in long-term SAGD operation.
In this study an iteratively coupled reservoir-geomechanics simulation is used to evaluate the extent of permanently stimulated and dilated volume as well as the efficacy of rupturing the impendent impermeable barriers. The geomechanical model incorporates a non-linear elasto-plastic constitutive model calibrated with the available McMurray sand public data. Estimates of the initial oilsand permeability and porosity were calibrated using the flow and shut-in periods of existing minifrac test data. The updated coupling parameters from the stress module in any time step enables the 3D thermal multi-phase reservoir model to sensitize various water injection scenarios and optimize the permeability enhancement affecting long-run performance of the SAGD recovery. The study reveals a minimum injection pressure about 15% larger than the initial vertical stress is required for an efficient dilation operation.
Thermal recovery processes in oil sands typically rely quite heavily on gravity drainage as one of the primary drive mechanisms. Steam Assisted Gravity Drainage (SAGD) is one such process that requires gravity drainage and vertical communication between the steam injector and producer for an efficient start-up and long-term recovery. The oil sands, especially those in the Alberta are very densely packed and if they are failed in shear at low effective stress they will dilate and increase permeability. This enhancement of permeability can be used to accelerate SAGD start-up as well as increase the efficiency of long-term drainage. This paper presents a calibrated reservoir and geomechanical model illustrating the pressure requirements (or effective stress) for significant permeability increases that will positively affect SAGD performance.
A detailed study has been conducted to model oil sand dilation by means of cold water injection prior to a typical SAGD process. The goal was to demonstrate an increase in absolute and water relative permeability from a rate and volume limited cold water injection into the SAGD well pairs. An advanced coupled reservoir and geomechanical simulation technique has been implemented to conduct this study.
Xiong, H. (University of Oklahoma) | Huang, S. (China University of Petroleum-Beijing) | Devegowda, D. (University of Oklahoma) | Liu, H. (China University of Petroleum) | Kim, C. (University of Oklahoma)
Steam Assisted Gravity Drainage (SAGD) is the most effective thermal recovery method to exploit oil sand. The driving force of gravity is generally acknowledged as the most significant driving mechanism in SAGD process. However, an increasing number of field cases have proven that pressure difference may even play an important role in some cases. Therefore, the objectives of this paper are to simulate the effects of injector-producer pressure difference on steam chamber evolution and SAGD production performance.
A series of 2D numerical simulations are conducted on the basis of MacKay River and Dover reservoir in West Canada to investigate the influence of pressure difference. Meanwhile, the effects of pressure difference on oil production rate, stable production time, steam chamber development were studied in detail. Moreover, by combining Darcy's law and heat conduction along with a mass balance in the reservoir, a modified mathematical model considering the effects of pressure difference is established to predict the SAGD production performance. Finally, the proposed model is validated by comparing calculated cumulative oil production and oil production rate with the simulation results.
The results indicate that the oil production first increases rapidly and then slows down when a certain pressure difference is reached. The impacts of pressure difference are much greater at steam chamber rising stage than at steam chamber expansion stage. Therefore, in the field, at the beginning of the SAGD recovery, it is better to augment pressure difference, while at the steam expansion stage, a lower pressure difference is preferred, so that a smaller chance of steam breakthrough and a higher economic benefit will be achieved. Besides, it is found that steam chamber expansion angle is a function of pressure difference. Based on this phenomenon, a new mathematical model is established considering the modification of the expansion angle which Butler treated it as a constant. With the proposed model, production performance, such as cumulative oil production and oil production rate can be predicted. Steam chamber shape is redefined at the rising stage and it changes from fan-shape to hexagonal-shape, but not the single fan-shape defined by Butler. This shape-redefinition can clearly explain why the greatest oil production rate does not happen when steam chamber reaches the cap-rock.
Literature surveys show few studies on how pressure difference influences steam chamber development and SAGD recovery. This paper provides a modified SAGD production model and also a totally new scope for SAGD EOR, which makes the pressure difference a new optimizable factor in field.
For thermal in-situ oil sands production, it is conventional to think that an emulsion pipeline remains essentially oil-wet. Ideally, an oil coating distributed on the pipe by the produced water-in-oil emulsion from a well pad is expected to give the needed corrosion protection for the operating life of the pipeline. Practically however, there are conditions under which this ideal scenario becomes no longer feasible, even for low API gravity heavy oil. These parameters affecting protection include but are not limited to water cut, well pad processing, steam cycle phenomena, reservoir characteristics, pipeline operating temperature, partitioning characteristics of the acid gases and their effects on water chemistry and passivation as well as other field operational practices.
From the experience of two case histories at a thermal in-situ oil sands project, this paper elaborates on many of the field parameters and how they influence the integrity of pipeline infrastructure by studying the various corrosion phenomena at play. Corrosion mitigation recommendations for these pipelines will also be presented.
Consideration of corrosion mechanisms in thermal oil recovery facilities should be divided into two categories, conditions with and without microorganisms present; the former is called microbiologically influenced corrosion (MIC). Constant monitoring of these facilities for MIC and controlling them when present is essential to corrosion management. If corrosive microorganisms are present in significant amounts, the probability of failure is high despite the presence of other corrosion mitigating factors including assumptions about oil-wetting, passive scale formation or the efficacy of a chemical inhibition program. This paper deals with non-microbiological corrosion issues and considers the following factors in the context of thermal oil production:
The in-situ steam based technology is still the main exploitation method for bitumen and heavy oil resources all over the world. But most of the steam-based processes (e.g., cyclic steam stimulation, steam drive and steam assisted gravity drainage) in heavy oilfields have entered into anexhaustion stage. Considering the long-lasting steam-rock interaction, how to further enhance the heavy oil recovery in the post-steam injection era is currently challenging the EOR (enhanced oil recovery) techniques. In this paper, we present a comprehensive review of the EOR processes in the post steam injection era both in experimental and field cases. Specifically, the paper presents an overview on the recovery mechanisms and field performance of thermal EOR processes by reservoir lithology (sandstone and carbonate formations) and offshore versus onshore oilfields. Typical processes include thein-situ combustion process, the thermal/-solvent process, the thermal-NCG (non-condensable gas, e.g., N2, flue gas and air) process, and the thermal-chemical (e.g., polymer, surfactant, gel and foam) process. Some new in-situ upgrading processes are also involved in this work. Furthermore, this review also presents the current operations and future trends on some heavy oil EOR projects in Canada, Venezuela, USA and China.
This review showsthat the offshore heavy oilfields will be the future exploitation focus. Moreover, currently several steam-based projects and thermal-NCG projects have been operated in Emeraude Field in Congo and Bohai Bay in China. A growing trend is also found for the in-situ combustion technique and solvent assisted process both in offshore and onshore heavy oil fields, such as the EOR projects in North America, North Sea, Bohai Bay and Xinjiang. The multicomponent thermal fluids injection process in offshore and the thermal-CO2and thermal-chemical (surfactant, foam) processes in onshore heavy oil reservoirs are some of the opportunities identified for the next decade based on preliminary evaluations and proposed or ongoing pilot projects. Furthermore, the new processes of in-situ catalytic upgrading (e.g., addition of catalyst, steam-nanoparticles), electromagnetic heating and electro-thermal dynamic stripping (ETDSP) and some improvement processes on a wellbore configuration (FCD) have also gained more and more attention. In addition, there are some newly proposed recovery techniques that are still limitedto the laboratory scale with needs for further investigations. In such a time of low oil prices, cost optimization will be the top concerns of all the oil companies in the world. This critical review will help to identify the next challenges and opportunities in the EOR potential of bitumen and heavy oil production in the post steam injection era.
Steam-assisted gravity drainage (SAGD) has been extensively applied in thermal recovery from oil sands reservoirs in the Athabasca region of Northern Alberta, Canada. As the steam chambers associated with SAGD well pairs become mature, a form of abandonment is often applied that may include pressure maintenance in the depleted zone. Quantification of potential surface subsidence associated with SAGD abandonment becomes critical especially when the mature wells are in proximity to future developments. In addition,induced shear stresses should be estimated to fulfill well-integrity requirements. In the context of this case study, first, the development of a static geomechanical model (SGM) derived from a fine-tuned geomodel realization is discussed, which forms the basis for the iteratively coupled simulation model. The calibration work flow of the coupled reservoir/geomechanical simulation model to historical heave data is then reviewed and the effects of different parameters on calibration quality are investigated. Finally, the estimation of subsidence and the induced shear stresses in the nearby wells are discussed, and the magnitude of residual heave is quantified. The results of this study show that only a fraction (up to 38%) of surface heave is reversible (in form of subsidence) during the abandonment phase. Therefore, the magnitude of the surface subsidence and the associated shear stresses are small. The modeling study has also shown that a small magnitude of subsidence may be recorded even 10 years after abandonment. However, more than 50% of the surface subsidence is observed in the first 2 years after abandonment. Other important findings of this study include documenting the effects of thief-zone interaction and pseudoundrained loading as they relate to irreversibility of surface heave; documenting the effects of various geomechanical parameters on the quality of calibration against the historical heave data; observation of the relative effects of the isotropic unloading, thermal expansion, and shear dilatancy on the magnitude of heave; and quantification of incremental, yet small, shear stresses along the nearby horizontal wells.