The last few years have seen the end of the Athabasca land play and the revival of interest in Alberta's bitumen resources in carbonate reservoirs. Of these, the Grosmont Formation is the most promising in terms of resource size and concentration. It is also the best known, in terms of having been the subject of several in situ pilots operated in the late '70s and early '80s.
The data recorded from these early pilots is priceless in terms of having a touchstone of reality for new process concepts. On the other hand, the interpretations written in those days ('before gravity') are not necessarily as helpful. This paper looks at the Grosmont in terms of facts and fundamentals, and presents the case for Grosmont exploitation.
There is good evidence that the Grosmont has very high bulk permeability as a result of karst porosity development and fracturing. This bodes well for the use of modern gravity drainage methods in the Grosmont.
Pressure drop along the horizontal wells and between the injector and producer could have a significant impact on SAGD process performance. However, this issue is poorly understood due to difficulties in simulating pressure drop. This paper presents the results of a numerical study on the topic.
When pressure drop between the injector and producer exists, the downhole vapour production rate must be increased significantly. Without adequate vapour production, the oil production rate is lower and SOR is higher. Increasing the vapour production rate may affect pad facility design as more vapour handling capacity is required under these conditions.
On the other hand, pressure drop inside the injection well may also alter steam distribution. However, the impact on oil production is limited as steam can move relatively easily inside the steam chamber. In the present case, oil production is reduced by approximately 5% when a pressure gradient along the injection well is considered.
Based on physical modelling, this paper discusses the feasibility of injecting additives to control the conformance of the cyclic steam stimulation (CSS) and steam drive processes in the Biquan 10 Block of the Henan Oil Field. The lab test results show that waterflooding with the addition of a carbamide surfactant can decrease residual oil saturation by 4.7% and that steam drive with the addition of this same surfactant can improve the sweep volume and increase the oil recovery factor by 17.5%. Also, field application results confirmed that injecting this surfactant in the CSS and steam drive processes can increase oil production, lower steam-oil ratio (SOR) and improve the economic benefitssignificantly.
When the bottomhole pressure (BHP) of volatile oil reservoirs falls below the bubblepoint pressure, two phases are created in the region around the wellbore, and a single phase (oil) appears in regions away from the well. The oil relative permeability reduces towards the near-wellbore region due to increasing gas saturation. This behaviour is quite similar to a gas-condensate reservoir below the dew-point, where the gas relative permeability is reduced due to the existence of a liquid bank around the wellbore. There are numerous publications in the literature concerning the behaviour diagnostic and well deliverability calculation in the case of gas-condensate reservoirs. However, the behaviour of volatile oil reservoirs is not well understood.
This paper aims at understanding the behaviour of volatile oil reservoirs. We used reservoir compositional simulations to predict the fluid behaviour below the bubblepoint, and then exported the flowing bottomhole pressure to a well test package to diagnose the existence of different mobility regions. In this study, the applicability of the two-phase pseudo-pressure method on volatile and highly volatile oil reservoirs was investigated, and it was found that this method is a very powerful tool for the prediction of true permeability and mechanical skin. Also, this method is capable of distinguishing between mechanical skin and condensate bank skin, which can be very helpful for designing after-drilling well treatment and IOR process designs.
Systematic studies are performed to investigate oxidation behaviour of three different types of crude oils (light oil, medium oil and Athabasca bitumen) by using two thermal analysis techniques: Thermogravimetry and Pressurized Differential Scanning Calorimetry. This study is also to look at the effect of pressure on energy generation associated with oxidation reactions in different temperature ranges.
It is observed that oxidation behaviours for light and medium oils are substantially different from those of Athabasca bitumen. The difference is seen in the temperature ranges where significant oxidation reactions occur. The experimental data in this work provide further evidence and addresses the difference in the oxidation behaviour of light oil and heavy oil.
Water availability is beginning to impact oil sands development and, as a result, several technologies to increase the percentage of recycled water are being evaluated. One such option being re-evaluated is the use of centrifuges to produce dry tailings that can accommodate overburden and soil replacement. Previous evaluations of centrifuge performance to capture water from the clay and silt tailings (mature fine tailings) components demonstrated some success but, at the time, at unacceptable costs. A better appreciation of the long-term costs of mature fine tailings storage has prompted a re-evaluation of centrifuge technology. The use of additives to improve centrifuge performance has significantly improved the results that can be achieved. Aside from the obvious positive environmental benefit of reclaiming the fluid fine (mature fine) tailings, the increase in the amount of water recycled will reduce the demand for fresh water from the Athabasca River. This paper discusses a laboratory-scale study of the water chemistry and clay/silt feed properties affecting centrifuge performance, as well as the results of a 20 tonne per hour pilot.
Certain Athabasca reservoirs have low pressures because they have been depleted due to production of overlying gas. Other reservoirs are naturally occurring low pressure shallow bitumen reservoirs. Hence, there is a need to develop or investigate recovery processes under which such low pressure reservoirs can be developed. As a result of this, experiments were initiated to extend the Expanding Solvent-SAGD (ES-SAGD) process application to low pressure Athabasca reservoirs in order to evaluate oil recovery from such reservoirs. The goal of these experiments is to develop a low pressure ES-SAGD process with better performance than, or comparable performance to, that of the high pressure SAGD process.
This paper describes five sets of laboratory experiments examining recovery processes, which includes a low pressure (500 kPag +/- 50 kPag) SAGD experiment, a propane-SAGD experiment, multi-component ES-SAGD (at low and high concentrations) experiments and a high pressure (2,100 kPag +/- 50 kPag) SAGD experiment. The results of these experiments are presented and analyzed in order to evaluate the performance of low pressure ES-SAGD in comparison to SAGD (at low and high pressure) and propane-SAGD at low pressure. The processes were assessed for recovery, recovery time, heat loss, steam chamber growth and energy efficiency.
The principal conclusion is that the low pressure multi-component ES-SAGD at the right concentration (mostly at low concentration) is fairly competitive with SAGD at a high pressure. The energy consumption in the steam or steam/solvent zone per oil recovered (ECDZ) for low pressure multi-component ES-SAGD experiments is much lower than the low pressure and high pressure SAGD tests. The propane-SAGD test recovery is very low, even at higher energy consumption, than that of the ES-SAGD experiment at low concentration. The work presented in this paper shows that the application of a multi-component ES-SAGD process in the field at low pressure is a practical option. It also shows that bitumen/heavy oil reservoirs that would have remained untapped due to low reservoir pressure could be produced at lower energy consumption per oil recovered if a low pressure ES-SAGD process at low concentration of the diluents is employed in the recovery of the oil.
High Pressure Air Injection (HPAI) is an improved oil recovery process in which compressed air is injected into typically deep, light oil reservoirs. Part of the oil reacts exothermically with the oxygen in the air to produce flue gas (mainly composed of nitrogen, carbon dioxide and water). Literature explaining the reaction mechanisms and phase interactions is available. Nevertheless, little effort has been devoted to describing gas, oil and water three-phase flow behaviour under HPAI reservoirconditions.
Three coreflood experiments were conducted on Berea sandstone core. The first experiment consisted of injecting flue gas into core at initial oil and connate water saturations to obtain liquid-gas relative permeability data. The second experiment was designed to evaluate oil re-saturation, after gas sweep, simulating an HPAI thermal front. The third experiment consisted of gas displacing both oil and water completing the data necessary to plot the three-phase relative permeability curves.
Reservoir simulation was used to adjust relative permeability curves and hysteresis parameters by matching the pressure drop and production data.
As SAGD is being increasingly used as a commercial technology to recover heavy oil and bitumen, it is essential to determine the most economical operating conditions for a SAGD operation by reservoir simulation. Furthermore, to support the decision-making process of a SAGD project, it is also important to quantitatively assess the uncertainty of its economicforecasts.
In this paper, the application of global optimization, experimental design, response surface generation and Monte Carlo simulation techniques in the workflow of SAGD simulation studies were demonstrated with a real field case example. The field case is an infill SAGD project with two planned SAGD well pairs and eight existing primary production wells which have 5 years of primary production. A bottomwater zone is also present.
Three major steps of the workflow are: 1) history matching primary production data; 2) optimizing SAGD performance; and 3) quantifying uncertainty of the SAGD forecasts. Firstly, experimental design and DECE (Designed Exploration and Controlled Evolution) optimization methods were used to achieve a faster and better history match than the traditional manual history match. Secondly, SAGD performance was optimized by adjusting the steam injection rate and producer liquid withdrawal rate during different SAGD operation periods. Finally, experimental design and response surface generation techniques were applied to build a polynomial response surface through which the net present value (NPV) of the SAGD project is correlated with uncertain parameters and a SAGD design parameter. Monte Carlo simulation was then performed to quantify the uncertainty of SAGD forecasts in terms of cumulative probability distribution of the NPV at different values of the SAGD designparameter.
The results show that the economics of this project are improved considerably through optimization. The optimum operating conditions obtained use a high initial steam rate and high production rate to develop the steam chamber. After the instantaneous steam-oil ratio reaches a certain value, both steam rate and production rate are lowered to prevent steam breakthrough to the bottomwater. The uncertainty of the project NPV was assessed, taking into consideration the uncertainties in high temperature relative permeability endpoints and the variation of the SAGD design parameter.
Gas-producing mudrock systems are playing an important role in the volatile energy industry in North America and will soon play an equally important role in Europe. Mudrocks are composed of very fine grained particles, and their pores are very small, at the scale of nanometers. Gas production from these strata is much greater than what is anticipated given their very low Darcy permeability. In this paper, images of nanopores obtained by Atomic Force Microscopy (AFM) are presented for the first time. Gas flow in nanopores cannot be described simply by the Darcy equation. Processes such as Knudsen diffusion and slip flow at the solid matrix separate gas flow behaviour from Darcy-type flow. We present a formulation for gas flow in the nanopores of mudrocks based on Knudsen diffusion and slip flow. By comparing this new gas flow formulation and Darcy flow for compressible gas, we introduce an apparent permeability term that includes the complexity of flow in nanopores, and it takes the form of the Darcy equation so that it can easily be implemented in reservoir simulators. Results show that the ratio of apparent permeability to Darcy permeability increases sharply as pore sizes reduce to smaller than 100 nm. Also, Knudsen diffusion's contributions to flow increase as pores become smaller. Unlike Darcy permeability, which is a characteristic of the rock only, permeation of gas in nanopores of mudrocks depends on rock, gas type and operating conditions.